Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.YesxNoo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.YesoNox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.YesxNo o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).YesxNoo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filerx

Accelerated Filero

Non-Accelerated Filer o(Do not check if a smaller reporting company)

Smaller reporting companyo

Emerging growth companyo

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).YesoNox

The aggregate market value of the registrant’s Class A common units held by non-affiliates computed by reference to the price at which the common equity was last sold on June 30, 2017, was $5,223,268,544.

As of February 13, 2018 the registrant has 326,517,110 Class A common units outstanding.

In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.” References to “Enbridge” refer collectively to Enbridge Inc., and its subsidiaries other than us. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of our General Partner that manages our business and affairs.

This Annual Report on Form 10-K includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Annual Report on Form 10-K speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) the effectiveness of the various actions we have taken resulting from our strategic review process; (2) changes in the demand for the supply of, forecast data for, and price trends related to crude oil and liquid petroleum, including the rate of development of the Alberta Oil Sands; (3) our ability to successfully complete and finance expansion projects; (4) the effects of competition, in particular, by other pipeline systems; (5) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (6) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B, (7) any fines, penalties and injunctive relief assessed in connection with any crude oil release; (8) changes in or challenges to our tariff rates; (9) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (10) permitting at federal, state and local level or renewals of rights of way. Forward-looking statements regarding sponsor support transactions or sales of assets (to Enbridge or otherwise) are further qualified by the fact that Enbridge is under no obligation to provide additional sponsor support and neither Enbridge nor any third party is under any obligation to offer to buy or sell us assets, and we are under no obligation to buy or sell any such assets. As a result, we do not know when or if any such transactions will occur. Any statements regarding sponsor expectations or intentions are based on information communicated to us by Enbridge, but there can be no assurance that these expectations or intentions will not change in the future.

For additional factors that may affect results, see “Item 1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K, which is available to the public over the Internet at the United States Securities and Exchange Commission’s (the SEC), website (www.sec.gov) and at our website (www.enbridgepartners.com).

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GLOSSARY

The following abbreviations, acronyms and terms used in this Annual Report on Form 10-K are defined below:

Alberta Clipper Pipeline

The pipeline that runs from the Canadian international border near Neche, North Dakota to Superior, Wisconsin on our Lakehead System

Partnership interests of the OLP related to all the assets, liabilities and operations of the Eastern Access Projects

Eastern Access Projects

Multiple expansion projects that will provide increased access to refineries in the United States Upper Midwest and in Canada in the provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States

EBITDA

Earnings Before Interest, Taxes, Depreciation and Amortization

EES

Enbridge Employee Services Inc., a subsidiary of our General Partner

Enbridge

Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner

Enbridge Management

Enbridge Energy Management, L.L.C.

Enbridge System

Canadian portion of the liquid petroleum mainline system

EP Act

Energy Policy Act of 1992

EPA

United States Environmental Protection Agency

ETCOP

Energy Transfer Crude Oil Pipeline

EUS

Enbridge (U.S.) Inc.

Exchange Act

Securities Exchange Act of 1934, as amended

FERC

Federal Energy Regulatory Commission

FSM

Facility Surcharge Mechanism

General Partner

Enbridge Energy Company, Inc., the general partner of the Partnership

IEPC

Illinois Extension Pipeline Company, L.L.C.

ICA

Interstate Commerce Act

IDUs

Incentive Distribution Units

IRS

Internal Revenue Service

ISDA®

International Swaps and Derivatives Association, Inc.

i-units

Special class of our limited partner interests

Lakehead System

United States portion of the liquid petroleum Mainline system

LIBOR

London Interbank Offered Rate — British Bankers’ Association’s average settlement rate for deposits in United States dollars

Mainline System

The combined liquid petroleum pipeline operations of our Lakehead System and the Enbridge system, which is a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada

MarEn

MarEn Bakken Company LLC

MEP

Midcoast Energy Partners, L.P.

Mid-Continent System

Crude oil pipelines and storage facilities located in the Mid-Continent region of the United States and includes the Cushing tank farm

MLP

Master Limited Partnership

MNPUC

Minnesota Public Utilities Commission

MPC

Marathon Petroleum Corporation

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NCI

Noncontrolling interest(s)

NGLs

Natural gas liquids

NDPC

North Dakota Pipeline Company, L.L.C.

Bakken Assets

Liquids petroleum pipeline gathering system and common carrier pipeline in the Upper Midwest United States that serves the Bakken formation within the Williston basin

NYSE

New York Stock Exchange

OLP

Enbridge Energy, Limited Partnership, also referred to as the Lakehead Partnership

Seventh Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P., also referred to as our partnership agreement

Partnership

Enbridge Energy Partners, L.P. and its consolidated subsidiaries

PHMSA

Pipeline and Hazardous Materials Safety Administration

SEC

United States Securities and Exchange Commission

Series AC interests

Partnership interests of the OLP related to all the assets, liabilities and operations of the Alberta Clipper Pipeline

Series EA interests

Partnership interests of the OLP related to all the assets, liabilities and operations of the Eastern Access Projects

Series ME interests

Partnership interests of the OLP related to all the assets, liabilities and operations of the U.S. Mainline Expansion projects

Southern Access

Southern Access Pipeline, a 42-inch pipeline that runs from Superior, Wisconsin to Flanagan, Illinois on our Lakehead System

U.S. GAAP

United States Generally Accepted Accounting Principles

U.S. L3R Program

The United States Line 3 Replacement Program

U.S. Mainline Expansion projects

Multiple projects that will expand access to new markets in North America for growing production from western Canada and the Bakken Formation

VIE(s)

Variable interest entity(entities)

WCSB

Western Canadian Sedimentary Basin

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PART I.

ITEM 1. BUSINESS

OVERVIEW

We are a publicly traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets in the United States of America. Our Class A common units are traded on the New York Stock Exchange (NYSE), under the symbol “EEP”

The following chart shows our organization and ownership structure as of December 31, 2017. The ownership percentages referred to below illustrate the relationships between us, Enbridge Energy Management, L.L.C., or Enbridge Management, Enbridge Energy Company, Inc., or our General Partner, and Enbridge Inc., or Enbridge, and its affiliates:

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We were formed in 1991 by Enbridge Energy Company, Inc., the general partner of the Partnership (General Partner), initially to own and operate the Lakehead System, which is the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada (Mainline System). A subsidiary of Enbridge Inc. (Enbridge) owns the Canadian portion of the Mainline system. Enbridge is the ultimate parent of our General Partner.

Enbridge Energy Management, L.L.C. (Enbridge Management) is a Delaware limited liability company that was formed in May 2002 to manage our business and affairs. Under a delegation of control agreement, our General Partner delegated substantially all of its power and authority to manage our business and affairs to Enbridge Management. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management is the sole owner of our i-units.

MIDCOAST GAS GATHERING AND PROCESSING DISPOSITION

In 2001, the Partnership acquired the East Texas system, which was the Partnership's first entry into the natural gas gathering and processing business. The Partnership continued expanding its natural gas assets, including the acquisition of the Midcoast system in 2002 and the acquisition of the North Texas system in 2003. In 2013, we formed Midcoast Energy Partners, L.P. (MEP) to serve as our primary vehicle for owning and growing our natural gas and NGL midstream business. MEP completed its initial public offering in 2013, and we continued to own all of the equity interests in MEP’s general partner, a majority limited partner interest in MEP and a minority limited partner interest in MEP’s operating subsidiary, Midcoast Operating, L.P. (Midcoast Operating).

On April 27, 2017, our General Partner acquired, for cash, all of the outstanding publicly held Class A common units of MEP, and shortly thereafter MEP ceased to be a publicly traded partnership. On June 28, 2017, we completed the sale of all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner (the Midcoast Disposition). The sale included our 48.4% limited partnership interest in Midcoast Operating, our 51.9% limited partnership interest in MEP and our 100% interest in Midcoast Holdings, L.L.C., the general partner of MEP.

The natural gas business included natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility, as well as rail and liquids marketing operations. The natural gas assets were primarily located in Texas and Oklahoma. The core basins are known as the East Texas basin, the Fort Worth basin and the Anadarko basin.

CONCLUSION AND RESULTS OF STRATEGIC REVIEW

On April 28, 2017, we announced the conclusion of our strategic review and undertook steps to position us as a pure-play liquids pipeline Master Limited Partnership (MLP) with a low-risk commercial profile, stable cash flows, a strong balance sheet, healthy distribution coverage, visible growth and limited external capital needs. Among the actions implemented as a result of the strategic review, we reduced our quarterly distribution from $0.583 per unit to $0.35 per unit or from $2.33 per unit to $1.40 per unit on an annualized basis, redeemed our outstanding Series 1 Preferred Units at a face value of $1.2 billion, commenced the sale of our interests in our Midcoast gas gathering and processing business, which was sold to our General Partner on June 28, 2017, repaid the deferred distribution balance on our Series 1 Preferred Units, restructured our capital structure and modified our incentive distribution rights and finalized a joint funding arrangement for our investment in the Bakken Pipeline System. See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Strategic Review for further detail.

BUSINESS

We manage our business in one segment - Liquids. The remainder of our business is presented as “Other” and consists of certain unallocated corporate costs. The following describes the operations of our business. For financial information, see Part II. Item 8. Financial Statements and Supplementary Data— Note 5 - Segment Information.

LIQUIDS

The map below presents the locations of our current Liquids systems’ assets and projects being constructed. The map also depicts some liquids pipelines assets owned by other Enbridge affiliates and projects being constructed to provide an understanding of how they interconnect with our Liquids systems.

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The following discussion provides an overview of North American production that is transported on our pipelines and the projects that we are pursuing to connect the growing supplies of this production to key refinery markets in the United States.

In 2017, we transported production from the Western Canadian Sedimentary Basin (WCSB) and the North Dakota Bakken formation. Western Canadian crude oil is an important source of supply for the United States. According to the latest available data for 2017 from the United States Department of Energy’s (DOE), Energy Information Administration (EIA), Canada supplied approximately 3.4 million barrels per day (Bpd), of crude oil to the United States, the largest source of United States imports. Over half of the Canadian crude oil moving into the United States was transported on the Enbridge Mainline system. The Canadian Association of Petroleum Producers (CAPP), a trade association representing a majority of our Lakehead System’s customers, forecasted as of June 2017 that future production from the Alberta oil sands will continue to experience steady growth during the next two decades with an additional 1 million Bpd of production by 2030, based on a subset of currently approved applications and announced expansions. We are well positioned to deliver growing volumes of crude oil that are expected from the WCSB to our existing as well as new markets.

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Along with Enbridge, we are actively working with our customers to develop transportation options that will alleviate capacity constraints in addition to providing access to new markets in the United States. Our market strategy is to provide safe, timely, economic, competitive and integrated transportation solutions to connect growing supplies of North American crude oil production to key refinery markets in the United States and Canada. Together, with Enbridge, we believe that our existing and future plans advance our collective vision of being one of the leading energy delivery companies in North America. In addition to this vision, we have advanced our Operational Risk Management Program.

We have a multi-billion dollar growth program underway, with projects coming into service through 2019, in addition to options to increase our economic interest in projects that are jointly funded by us and Enbridge. This growth program includes expansions to our Mainline system as well as replacement of the Line 3 pipeline to ensure WCSB production has efficient and reliable access to markets in the United States Midwest and beyond. For further details regarding our growth program, refer to Part II.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Growth Projects - Commercially Secured Projects

The United States Line 3 Replacement Program (U.S. L3R Program) will support the safety and operational reliability of the system, enhance system flexibility and allow us and Enbridge to optimize throughput from western Canada into Superior, Wisconsin. The U.S. L3R Program is expected to achieve the original capacity of approximately 760,000 Bpd. This project, along with the other projects on the Mainline, will provide increased market access for producers to refineries in the United States upper-Midwest, eastern Canada, and the United States Gulf Coast refining centers. For further details regarding our projects, refer to Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Results of Operations - By Segment.

In February 2017, we completed the acquisition of an effective 27.6% equity interest in the Bakken Pipeline System through our joint venture with Marathon Petroleum Corporation (MPC). This system was placed into service on June 1, 2017 and will further enhances our strategy of providing efficient market access solutions for Bakken production, while providing the opportunity for the implementation of joint tolls with the Energy Transfer Crude Oil Pipeline (ETCOP), enhancing market access opportunities for our customers and creating a new flow path through the Mainline system to the eastern United States Gulf Coast. Refer to Part II.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments for further details.

Our Lakehead System, together with the Enbridge system in Canada, form the Mainline system, which has been in operation for over 60 years and forms the longest liquid petroleum pipeline system in the world. The Mainline system operates in a segregated, or batch mode allowing the transportation of over 39 oil commodities typically classified as light, medium, or heavy crude oil, condensate, and natural gas liquids (NGLs). The Mainline system serves all of the major refining centers in the Great Lakes and Midwest regions of the United States and the provinces of Ontario and Quebec, Canada. The Lakehead System is the United States portion of the Mainline system. It is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission (FERC) and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States.

Over the past seven years, we have completed the largest pipeline expansion program in our history in order to accommodate the growing upstream supply that will feed our completed downstream market access projects. Our customers have long development timelines and need assurance that an adequate pipeline infrastructure will be in place in time to transport the additional production resulting from completion of their projects. We have successfully completed several projects over the years and have substantially completed our Mainline Expansion Project and commenced construction on components of the United States Line 3 Replacement Program, which will provide the needed incremental market access for both our producer and refiner customers located in our primary target markets.

Our Lakehead System is strategically interconnected to multiple refining centers and transportation hubs located within Petroleum Administration for Defense Districts (PADD), such as: Chicago, Illinois; Patoka, Illinois; and Cushing, Oklahoma (PADDII). In addition, we are also strategically connected to the largest U.S. refining center in the United States Gulf Coast through other pipelines owned by Enbridge and its affiliates. WCSB production in excess of Western Canadian demand moves on existing pipelines into primarily PADD II, with secondary markets including: the United States Gulf Coast (PADD III); the Rocky Mountain states (PADD IV); the Anacortes area of Washington state (PADD V); and Eastern Canada (Ontario and Quebec).The Lakehead System mainly serves the PADD II market directly and the PADD III market indirectly. Bakken production in excess of local demand primarily moves on existing pipelines into PADD II or is transported by rail to coastal Canadian and United States refining markets. The United States Gulf Coast continues to be an attractive market for WCSB producers due to the market’s large refining capacity designed to process heavy crude oil. The forecasted long-term incremental growth of Canadian oil sands and Bakken production

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provides stability for existing pipeline throughputs to historical markets as well as creating new growth opportunities available to both us and our competitors.

Customers

Our Lakehead System operates under month-to-month transportation arrangements with our shippers. During 2017, approximately 40 shippers tendered crude oil and liquid petroleum for delivery through our Lakehead System. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Lakehead System. Our customers include integrated oil companies, major independent oil producers, refiners and marketers. For further details regarding revenues from our largest third party customers see Part II. Item 8. Financial Statements and Supplementary Data— Note 5 - Segment Information

Supply and Demand

Our Lakehead System is part of the longest crude oil pipeline in the world and is a critical component of the North American crude oil supply pipeline network. Lakehead is well positioned as the primary transporter of western Canadian crude oil and continues to benefit from past and anticipated future crude oil production growth from the Alberta Oil Sands, as well as recent development in tight oil production in North Dakota. Aside from the receipt locations on the Mainline system within Canada, our Lakehead System receives injections from locations within the United States. Clearbrook, Minnesota is the receipt location for United States Bakken production, and other United States sources are received at Lewiston, Michigan and Mokena, Illinois.

Crude oil originating from the WCSB comprises the majority of Lakehead System deliveries. According to Natural Resources Canada (NRCan), Canada is currently ranked third in the world for total proved reserves, just behind Venezuela and Saudi Arabia, respectively. NRCan estimates that 97% of Canada’s total proved reserves are attributed to Alberta’s oil sands bitumen, with the remainder being conventional oil sources. The Alberta Energy Regulator, estimates 166.6 billion total barrels, or approximately 165 billion and 1.6 billion barrels of established proved bitumen and conventional reserves, respectively, remain for the region. The National Energy Board (NEB) estimates that total production from the WCSB averaged approximately 4.0 million Bpd in 2017 and 3.6 million in 2016. Furthermore, these production levels are expected to grow in the future, as previously discussed.

The growth forecast in the oil sands will be primarily driven by steam assisted gravity drainage (SAGD), projects in the long-term. Mining projects are the main contributor to near-term growth, with other development projects on hold until prices recover and well economics improve. Based on projects currently under construction in western Canada, the incremental productive capacity that would have access to our systems is reported to increase over the next three years by approximately 404,000 Bpd.

Lakehead throughput volumes are primarily supplied by crude oil produced in the Canadian oil sands and Bakken resource plays. North Dakota’s Bakken/Three Forks resource play has become a major component of United States domestic supply. In 2017, production averaged 1.1 million Bpd and is expected to remain at that level through 2018. Forecasts of western Canadian crude oil supply are periodically completed by Enbridge, CAPP and the NEB, among others. The June 2017 CAPP forecast predicts western Canada oil sands production is expected to grow by 1 million Bpd to 3.7 million Bpd by 2030. This compares with an expected increase of 30,000 Bpd from conventional production sources over the same time frame. Compared to the 2016 forecast, CAPP kept its oil sands production forecast at 3.7 million Bpd due to the low oil price environment and constraints arising from oil sands cost competitiveness and delays in project schedules. The production growth forecasted out of our primary supply markets requires additional pipeline capacity.

PADD II is the primary demand market for our Lakehead System. Deliveries on our Lakehead System are negatively affected by periodic maintenance, other competitive transportation alternatives, or refinery turnarounds and other shutdowns at producing plants that supply crude oil. Based on growth in western Canada and Bakken crude oil supply and Lakehead operational performance improvements, deliveries on our Lakehead System are expected to be higher than the 2.7 million Bpd of actual deliveries experienced during 2017.

The latest data available from the EIA shows that total PADD II demand was 3.7 million Bpd. PADD II produced 1.7 million Bpd and imported 2.4 million Bpd from Canada and other regions located in the United States, with exports comprising the remaining difference between PADD II supply and demand. Imports from Canada comprised 99% of total PADD II crude oil imports, with approximately 65% or 1.5 million Bpd transported on our Lakehead System. The remaining barrels were imported via competitor pipelines from Alberta and offshore sources via the United States Gulf Coast or regional transfers from PADD III or PADD IV.

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Lakehead System deliveries for 2017 were approximately 99,000 Bpd higher than delivery volumes for 2016. Total deliveries from our Lakehead System averaged 2.7 million Bpd in 2017, meeting approximately 71% of the refinery capacity in the greater Chicago area; 81% of the Minnesota refinery capacity; and 81% of Ontario refinery capacity. Refinery configurations and crude oil requirements within PADD II continue to create an attractive market for western Canada and Bakken supply. Crude oil demand in PADD II averaged 3.7 million Bpd, an increase of 134,000 Bpd from 2016, while overall refining utilization grew to 94% from 92% when compared to the prior year.

Competition

WCSB crude oil competes with local and imported crude oil. Of all the pipeline systems that transport crude oil out of Canada, the Mainline system transported approximately half of all Canadian crude oil imports into the United States in 2017.

Given the expected increase in crude oil production from the Alberta Oil Sands over the next 10 years, alternative transportation proposals have been presented to crude oil producers. Competitors’ proposals to WCSB and Bakken shippers include expanding, twinning, extending and building new pipeline assets. These proposals and projects are in various stages of regulatory approval.

Transportation of crude oil by rail has also emerged as a competitor primarily due to the lack of pipeline capacity for the WCSB and Bakken regions. As a result, a significant amount of rail loading capacity has been constructed and is proposed in both markets. Rail transportation becomes less competitive, however, as crude oil price differentials narrow between key markets due to high transportation costs relative to cost of transportation by pipeline.

These competing alternatives for delivering western Canada crude oil into the United States and other markets could erode shipper support for further expansion of our Lakehead System. Accordingly, competition could also impact throughput on and utilization of the Mainline system. The Mainline system, however, offers significant cost savings and flexibility to shippers.

Deliveries for our Lakehead System over the past five years were as follows:

2017

2016

2015

2014

2013

(thousands of Bpd)

United States

Light crude oil

416

492

500

496

473

Medium and heavy crude oil

1,606

1,471

1,364

1,167

948

NGL

5

5

5

6

6

Total United States

2,027

1,968

1,869

1,669

1,427

Canada

Light crude oil

464

427

294

298

247

Medium and heavy crude oil

108

100

77

72

76

NGL

74

79

75

74

66

Total Canada

646

606

446

444

389

Total Deliveries

2,673

2,574

2,315

2,113

1,816

Barrel miles (billions per year)

756

724

640

582

487

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Mid-Continent System

Our Mid-Continent System, which we have owned since 2004, is located within PADD II and is comprised of storage terminals at Cushing, Oklahoma.

The storage terminals consist of over 80 individual storage tanks ranging in size from 78,000 to 570,000 barrels. The total storage shell capacity of our Mid-Continent System is approximately 20 million barrels. A portion of the storage facilities are used for operational purposes, while we contract the remainder of the facilities with various crude oil market participants for their term storage requirements. Contract fees include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from connecting pipelines and terminals and blending fees.

The Cushing Terminal continues to change with market dynamics and we are well positioned to capitalize on potential growth projects. We also see long-term strategic value for the terminals and plan to expand both its capacity and connectivity as market conditions improve.

In December 2016, we entered into an agreement to sell the Ozark Pipeline system to a subsidiary of MPLX LP. On March 1, 2017, we completed the sale of the Ozark Pipeline system to a subsidiary of MPLX LP for cash proceeds of approximately $220 million. For more information, refer to Part II.Item 8. Financial Statements and Supplementary Data— Note 9 - Property, Plant and Equipment.

Customers

Our Mid-Continent System operates under long-term storage arrangements with shippers. These arrangements are up to 10 years in length and include producers, refiners and marketers. Storage utilization depends on a variety of factors, including price differentials, supply and apportionment among others.

Supply and Demand

Demand for storage capacity at Cushing, Oklahoma has remained high as customers continue to value the flexibility and optionality available with this service as well as the superior connectivity that our terminal offers. Our storage

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terminals rely on demand for storage service from numerous oil market participants. Producers, refiners, marketers and traders value our storage capacity in Cushing, Oklahoma for a number of different reasons, including batch scheduling, stream quality control, inventory management, blending and speculative trading opportunities.

Competition

Competitors to our storage facilities at Cushing, Oklahoma include large integrated oil companies, private entities and other midstream energy partnerships. Many of these competitors have the capability to expand in the future and be competitive on quality of service, reliability, increased connectivity and price.

Bakken Assets

Our Bakken Assets consist of the North Dakota System and the Bakken Pipeline System. The North Dakota System is a joint operation that includes both a Canadian and United States portion. The United States portion of the North Dakota System is comprised of a crude oil gathering and interstate pipeline transportation system servicing the Williston Basin in North Dakota and Montana, which includes the Bakken and Three Forks formations. The gathering pipelines collect crude oil from nearly 80 different receipt facilities located throughout western North Dakota and eastern Montana, with delivery to Clearbrook for service on the Lakehead System or a variety of interconnecting pipeline and rail export facilities. The United States interstate portion of the pipeline extends from Berthold, North Dakota to the International Boundary near North Portal, North Dakota and connects to the Bakken Canadian entity at the border to bring crude oil into Cromer, Manitoba (the Bakken System).

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Traditionally, the majority of our pipeline deliveries have been made into interconnecting pipelines at Clearbrook, Minnesota where two other pipelines originate: (i) a third-party pipeline serving St. Paul, Minnesota refinery markets; and (ii) our Lakehead System providing further pipeline transportation on the Enbridge system into the Great Lakes, eastern Canada and United States Midwest refinery markets that include Cushing, Oklahoma, Patoka, Illinois, and other pipelines delivering crude oil to the United States Gulf Coast. We have significantly increased the pipeline capacity of our North Dakota System through a series of projects in recent years while continuing to serve the system’s traditional markets in order to provide an array of market options and services.

On February 15, 2017, we announced the closing of our acquisition of an effective 27.6% ownership interest in the Bakken Pipeline System. We formed a joint venture with MPC to acquire a passive 49% equity interest in Bakken Pipeline Investments LLC (BPI) an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., which owns 75% of the Bakken Pipeline System. We and MPC indirectly hold a 75% and 25%, respectively of our 49% passive interest in BPI. The Bakken Pipeline System connects the Bakken formation in North Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access Pipeline (DAPL) and the Energy Transfer Crude Oil Pipeline projects (ETCOP). DAPL consists of 1,172 miles of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. Initial capacity is in excess of 470,000 Bpd of crude oil with the potential to be expanded to 570,000 Bpd. The Energy Transfer Crude Oil Pipeline consists of 62 miles of new 30-inch diameter pipe, 686 miles of converted 30-inch diameter pipe and 40 miles of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas. The Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.

Customers

Customers of our North Dakota System include refiners of crude oil, producers of crude oil and purchasers of crude oil at the wellhead, such as marketers, that require crude oil gathering and transportation services. Producers range in size from small independent owner/operators to large integrated oil companies. During 2017, approximately 304 shippers tendered crude oil for service on our North Dakota System.

Supply and Demand

Similar to our Lakehead System, our North Dakota System depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States and the ability of crude oil producers to maintain their crude oil production and exploration activities. The state of North Dakota reported production levels of 1.1 million Bpd as of November 2017 with projections remaining at that level through 2018.

Competition

Due to the growth in production from these formations over the last several years, competition has increased substantially. Traditional competitors of our North Dakota System include refiners, integrated oil companies, interstate and intrastate pipelines or their affiliates and other crude oil gatherers. Many crude oil producers in the oil fields served by our North Dakota System have alternative gathering facilities available to them or have the ability to build their own assets, including their own rail loading facilities.

Currently, the primary competition to our North Dakota System is DAPL. As discussed, we purchased a minority stake in the Bakken Pipeline System, including DAPL, which entered into service June 1, 2017.

SEASONALITY

Drilling activities of producers within areas of our liquids pipeline network increase in winter months as the ground on which their drilling rigs are placed is frozen and inaccessible terrain becomes available. Western Canada typically experiences an increase in production during the winter months to align with consumer demand for refined products. Demand for crude oil diminishes into the spring and early fall as mid-west and gulf coast refineries undergo maintenance and turnaround activities. Seasonality exposure on the Enbridge Mainline is typically limited to light barrels as strong heavy supply and demand have resulted in the Mainline being oversubscribed (apportioned) for heavy capacity. In addition, system optimization initiatives in 2017 have further improved Enbridge’s utilization on the Mainline system. These initiatives have added flexibility to allocate crude to various lines further mitigating any seasonality risk on light throughputs. In addition, any further exposure to fluctuations in revenue as a result of seasonality is partially mitigated on our Lakehead System through authoritative accounting provisions applicable to regulated operations.

REGULATION

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REGULATION BY THE FERC OF INTERSTATE COMMON CARRIER LIQUIDS PIPELINES

The FERC regulates the interstate pipeline transportation of crude oil, petroleum products, and other liquids such as NGLs. Our Lakehead System, North Dakota and Bakken Systems are our primary interstate common carrier liquids pipelines subject to regulation by the FERC under the Interstate Commerce Act (ICA), the Energy Policy Act of 1992 (EP Act), and rules and orders promulgated thereunder. As common carriers in interstate commerce, these pipelines provide service to any shipper who makes a reasonable request for transportation services, provided that the shipper satisfies the conditions and specifications contained in the applicable tariff. The ICA requires us to maintain tariffs on file with the FERC that set forth the rates we charge for providing transportation services on our interstate common carrier pipelines, as well as the rules and regulations governing these services.

The ICA gives the FERC the authority to regulate the rates we can charge for service on interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and that they not be unduly discriminatory or unduly preferential to certain shippers. The ICA permits interested parties to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate the rates to determine if they are just and reasonable. If the FERC finds the new or changed rate unlawful, it is authorized to require the carrier to refund, with interest, the amount of any revenues in excess of the amount that would have been collected during the term of the investigation at the rate properly determined to be lawful. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

In October 1992, Congress passed the EP Act, which deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment, or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period, to be just and reasonable under the ICA (i.e., “grandfathered”). The EP Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party must show: (i) that it was contractually barred from challenging the rates during the relevant 365-day period; (ii) that there has been a substantial change after the date of enactment of the EP Act in the economic circumstances of the pipeline or in the nature of the services that were the basis for the rate, or (iii) that the rate is unduly discriminatory or unduly preferential.

The FERC determined our Lakehead System rates are not covered by the grandfathering provisions of the EP Act because they were subject to challenge prior to the effective date of the statute. The rates for our North Dakota System in effect at the time of the EP Act should be found to be subject to the grandfathering provisions of the EP Act because those rates were not suspended or subject to protest or complaint during the 365-day period established by the EP Act.

The EP Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561 which adopted an indexing rate methodology for petroleum pipelines. Under these regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels may be protested, but such protests generally must show that the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling, although a pipeline is not required to reduce its rate below the level grandfathered under the EP Act. Under Order No. 561, a pipeline must as a general rule utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

The tariff rates for our Lakehead System are set using a combination of the FERC indexing rules (which apply to the base rates on that system) and FERC-approved surcharges for particular projects that were approved under the FERC’s settlement rules. The tariff rates for the North Dakota and Bakken Systems are set through a combination of the FERC indexing rules and contractual agreements.

The inflation index applied to those rates subject to the FERC indexing rules is determined by a formula that is established by FERC and is subject to review every five years. On December 18, 2015, the FERC set the index for the period from July 2016 through June 2021 at Producer Price Index for Finished Goods plus 1.23 percentage points. Based on this formula, the index resulted in an increase of approximately 0.2% for 2017 and a decrease of approximately 2.0% for 2016.

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On October 20, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking (ANOPR) seeking comments on proposed changes to its review of oil pipeline index rate filings and reporting requirements. Specifically, the FERC proposes to reject increases to indexed rates and indexed rate ceilings if certain criteria are met. Such rate increase rejections would be outright and would not be prompted by a shipper protest (as is the case currently) or involve a hearing into the merits of the rate increase. An ANOPR is an initial step taken by a regulatory agency to obtain comments from impacted parties. Before issuing a final rule regarding these issues the FERC must also undertake a Notice of Proposed Rulemaking (NOPR) process. Given the fact that the FERC did not have quorum for much of 2017, no action was taken regarding this ANOPR in 2017. It is unclear when this issue will be resolved.

FERC ALLOWANCE FOR INCOME TAXES IN INTERSTATE COMMON CARRIER PIPELINE RATES

Under current FERC policy, pipelines regulated by the FERC that are owned by entities organized as MLPs, may include an income tax allowance in their cost-of-service rates to the extent the income generated from regulated activities was subject to an actual or potential income tax liability. Pursuant to this policy, a FERC-regulated pipeline that is a tax pass-through entity seeking such an income tax allowance must establish that its owners, partners or members have an actual or potential income tax obligation on the partnership’s income from regulated activities. Whether a particular pipeline’s owners have an actual or potential income tax liability is reviewed by the FERC on a case-by-case basis. The MLP income tax allowance is relevant to those Lakehead projects whose costs are recovered on a cost-of-service based mechanism and would also be relevant to the extent any of our FERC regulated oil pipeline systems were to file cost-of-service rates. Entitlement to an income tax allowance is assessed under the FERC policy statement and the facts existing at the relevant time.

The current FERC income tax allowance policy has recently been drawn into question by a decision of the United States Court of Appeals (D.C. Circuit). In its July 1, 2016 decision in the United Airlines case the court found that the FERC had failed to demonstrate that its income tax policy statement - in conjunction with its rate of return policy statement - does not result in double recovery of taxes for partnerships and asked the FERC to establish an income tax recovery mechanism for which it can demonstrate that there is no double recovery. It is unclear at this point whether the current FERC income tax policy will be upheld or whether the FERC will need to change its policy and if so what the new mechanism might look like. On December 15, 2016 in Docket No. PL17-1-000, the FERC issued its Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs, in which the FERC requested comments regarding how to address any double recovery resulting from the FERC’s current income tax allowance and rate of return policies. During 2017, numerous parties filed comments in response to the FERC’s request but the FERC has not yet acted on the comments. It is unclear when this issue will be resolved.

Further, effective January 2018, the "Tax Cuts and Jobs Act" (TCJA) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the TCJA being signed into law, filings have been made at FERC requesting that FERC require pipelines regulated by FERC to lower their transportation rates to account for lower taxes. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. However, FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may only impact two of such components, the allowance for income taxes and the amount for accumulated deferred income taxes. Because our existing jurisdictional rates were established based on a higher corporate tax rate, FERC or our shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates we currently charge.

ACCOUNTING FOR PIPELINE ASSESSMENT COSTS

The FERC’s policies describe how FERC-regulated companies should account for costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation (DOT) and the Pipeline and Hazardous Materials Safety Administration (PHMSA). FERC regulated companies are generally required to recognize costs incurred for performing pipeline assessments that are part of a pipeline integrity management program as a maintenance expense in the period in which the costs are incurred. Costs for items such as rehabilitation projects designed to extend the useful life of the system can continue to be capitalized to the extent permitted under the existing rules. Consistent with the FERC’s policies, we expense all internal inspection costs for all our pipeline systems, whether or not they are subject to the FERC’s regulation. Refer to Part II. Item 8. Financial Statements and Supplementary Data— Note 2 - Significant Accounting Policies included in our consolidated financial statements of this Annual Report on Form 10-K for additional discussion.

OTHER REGULATION

The governments of the United States and Canada have, by treaty, agreed to reduce barriers to foreign trade and stimulate the flow of goods and services between the United States and Canada, which includes the passage of oil

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and natural gas through the pipelines of one country across the territory of the other. Individual international border crossing points require United States government permits that may be terminated or amended at the discretion of the United States Government. These permits provide that pipelines may be inspected by or subject to orders issued by federal and, on occasion, state government agencies.

Safety Regulation and Environmental

GENERAL

Our transmission pipelines, storage facilities and railcar operations are subject to extensive environmental, operational and safety regulation at the federal and state level. The added costs imposed by regulations are generally no different than those imposed on our competitors. The failure to comply with such rules and regulations can result in substantial penalties and/or enforcement actions and added operational costs.

PIPELINE SAFETY AND TRANSPORTATION REGULATION

Our transmission pipelines are subject to regulation by the DOT and the PHMSA, under the Pipeline Safety Act (PSA), specifically Volume 49 of the Code of Federal Regulations, Part 195 (hazardous liquids). The regulations pertain to the design, installation, testing, construction, operation, replacement and management of transmission pipeline facilities. PHMSA is the agency charged with regulating the safe transportation of hazardous materials under all modes of transportation, including interstate and intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations and imposing direct mandates on operators of pipelines. The most recent reauthorization occurred in 2016.

The National Transportation Safety Board (NTSB) has recommended that the PHMSA make a number of changes to its rules. Congress also has mandated that PHMSA adopt regulations to implement these recommendations, along with a number of additional regulatory measures. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above.

In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

When hydrocarbons are released into the environment or violations identified during an inspection, PHMSA may issue a civil penalty or enforcement action, which can require internal inspections, pipeline pressure reductions and other methods to manage or verify the integrity of a pipeline in the affected area. In addition, NTSB may perform an investigation of a significant accident to determine the probable cause and issue safety recommendations to prevent future accidents. Any release that results in an enforcement action or NTSB investigation, such as those associated with Line 6B near Marshall, Michigan could have a material impact on system throughput or compliance costs.

Where we have identified instances of non-compliance with respect to our pipeline and railcar operations, we have taken actions to remediate the situations. Nevertheless, significant operating expenses and capital expenditure could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the capabilities of our current pipeline control system or other safety equipment.

ENVIRONMENTAL REGULATION

General

Our operations are subject to complex federal, state and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling, storage and release of crude oil and other liquid hydrocarbon materials. As with the pipeline and processing industry in general, complying with current and anticipated environmental laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our

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maintenance capital expenditures and net income, we believe that they do not affect our competitive position since the operations of our competitors are generally similarly affected.

In addition to compliance costs, violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions, banning or delaying certain activities.

There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of crude oil, NGLs, or other substances from our pipelines or storage facilities. Such accidental releases could, to the extent not insured, subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines, penalties or damages for related violations of environmental laws or regulations.

Although we are entitled, in certain circumstances, to indemnification from third parties for environmental liabilities relating to assets we acquired from those parties, these contractual indemnification rights are limited, and accordingly, we may be required to bear substantial environmental expenses. However, we believe that through our due diligence process, we identify and manage substantial issues.

Air and Water Emissions

Our operations are subject to the Clean Air Act (CAA), the Clean Water Act (CWA) and comparable state and local statutes. We believe we are in material compliance with these laws and regulations. We anticipate that we will incur costs over the next several years for air pollution control equipment and spill prevention measures in connection with maintaining our existing facilities and obtaining permit approvals for any new or acquired facilities.

In June 2016, the United States Environmental Protection Agency (EPA) issued final rules specific to the oil and gas industry to regulate methane and volatile organic compound (VOC) emissions from new and modified facilities in transportation and storage, gathering and boosting, production and processing facilities, including fugitive emission leak detection and repair requirements. On April 19, 2017, the EPA announced its intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions for 90 days. Petitioners challenged the administrative stay in the D.C. Circuit, and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed rules effective. These methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking in the future, which action is likely to be challenged in the courts. In November 2016, the EPA issued an Oil and Gas Information Collection Request (ICR) covering methane and VOC emissions from the oil and gas industry. Enbridge received notification of the request on November 22, 2016, but in March 2017 before we were required to respond, the EPA subsequently withdrew the ICR.

In June 2015, the EPA and the United States Army Corps of Engineers (Army Corps) published a final rule to clarify the federal jurisdictional reach over wetlands and waterbodies. This regulation is the subject of numerous ongoing legal challenges. The United States Sixth Circuit Court of Appeals stayed implementation of the rule nationwide in October 2015 pending review, but on January 22, 2018, the United States Supreme Court held that legal challenges to the rule must first be heard at the district court level rather than the appellate court level. Additionally, the EPA and the Army Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, and they announced their intent to issue a new rule defining the reach of federal jurisdiction. On February 6, 2018 the EPA and Army Corps issued a final rule amending the effective date of the 2015 rule to February 6, 2020. Challenges to this rule have been filed and remain pending in various federal courts. As a result, future implementation of the June 2015 rule is uncertain at this time. If implemented, this final rule has the potential to increase our operating and capital costs to construct, maintain and upgrade equipment and facilities.

The Oil Pollution Act (OPA) was enacted in 1990 and amends parts of the CWA and other statutes as they pertain to the prevention of and response to oil spills. Under the OPA, we could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from our facilities into navigable waters, along shorelines or in an exclusive economic zone of the United States. The OPA also imposes certain spill prevention, control and countermeasure requirements for many of our non-pipeline facilities, such as the preparation of detailed oil spill emergency response plans and the construction of dikes or other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or release. For our liquid pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. For our non-transportation facilities, such as storage tanks that are not integral to our pipeline transportation system, the OPA regulations are promulgated by the EPA.

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For all proposed rules, we will continue to track the progress through involvement in industry groups and will comply with any regulatory requirements that enter into force. We do not expect a material effect on our financial statements as a result of compliance efforts.

Hazardous Substances and Waste Management

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA, or the “Superfund” law) and similar state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owners or operators of waste disposal sites and companies that disposed or arranged for disposal of hazardous substances found at such sites. We may generate some wastes that fall within the definition of a “hazardous substance.” We may, therefore, be subject to strict, joint and several liability under CERCLA for all or part of any costs required to clean up and restore sites at which such wastes have been disposed, for damages to natural resources, and for the cost of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws may apply to a broader range of substances than CERCLA and, in some instances, may offer fewer exemptions from liability. We have not received any notification that we may be potentially responsible for material cleanup costs under CERCLA or similar state laws.

Site Remediation

We own and operate a number of pipelines, gathering systems, and storage facilities that have been used to transport, distribute, store and process crude oil and other petroleum products. Many of our facilities were previously owned and operated by third parties whose handling, disposal and release of petroleum and waste materials were not under our control. The age of the facilities, combined with the past operating and waste disposal practices, which were standard for the industry and regulatory regime at the time, have resulted in soil and groundwater contamination at some facilities due to historical spills and releases. Such contamination is not unusual within the petroleum industry. Historical contamination found on, under or originating from our properties may be subject to CERCLA, the Resource Conservation & Recovery Act and analogous state laws as described above.

Under these laws, we could incur substantial expense to remediate such contamination, including contamination caused by prior owners and operators. In addition, Enbridge Management, as the entity with managerial responsibility for us, could also be liable for such costs to the extent that we are unable to fulfill our obligations. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate.

Endangered Species

New projects may require approvals and environmental analyses under federal or state laws, including the National Environmental Policy Act and the Endangered Species Act, that result in prohibitions on activities that can result in harm to specific species of plants and animals. The often lengthy regulatory review and project approval process, as well as prohibitions or requirements for capital expenditures to reduce a facility’s impacts on a species, may result in increased costs and liabilities that could materially and negatively affect the viability of a project.

EMPLOYEES

Neither we nor Enbridge Management have any employees. Our General Partner has delegated to Enbridge Management, pursuant to a delegation of control agreement, substantially all of the responsibility for our day-to-day management and operation. Our General Partner, however, retains certain functions and approval rights over our operations. To fulfill its management obligations, Enbridge Management has entered into agreements with Enbridge and several of its affiliates to provide Enbridge Management with the necessary services and support personnel who act on Enbridge Management’s behalf as its agents. We are ultimately responsible for reimbursing these service providers based on the costs that they incur in performing these services.

INSURANCE

Our operations are subject to many hazards inherent in the liquid petroleum gathering, treating, processing and transportation industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We are included in the comprehensive insurance program maintained by Enbridge for its subsidiaries. This program includes insurance coverage in types

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and amounts and with terms and conditions that are generally consistent with coverage considered customary for our industry.

In the event of multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge and other Enbridge subsidiaries.

We can make no assurance that the insurance coverage we maintain will be available or adequate for any particular risk or loss or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows.

TAXATION

We are not a taxable entity for United States federal income tax purposes. Generally, United States federal and state income taxes on our taxable income are borne by our individual partners through the allocation of our taxable income. In a limited number of states, an income tax is imposed upon us and generally, not our individual partners. The income tax that we bear is reflected in our consolidated financial statements. The allocation of taxable income to our individual partners may vary substantially from net income reported in our consolidated statements of income.

AVAILABLE INFORMATION

We make available free of charge on or through our Internet website http://www.enbridgepartners.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended, or Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

We encourage you to consider carefully the risk factors described below, in addition to the other information contained in or incorporated by reference into this Annual Report on Form 10-K.

RISKS RELATED TO OUR BUSINESS

WE MAY NOT HAVE SUFFICIENT CASH FLOWS TO ENABLE US TO CONTINUE TO PAY DISTRIBUTIONS AT THE CURRENT LEVEL.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at the current level. As part of our previously completed strategic review, which concluded in April 2017, we considered the sustainability of our level of distributions, which had been adversely affected the performance of our natural gas business, cyclical downturns and other factors. Upon completion of the strategic review, we announced several actions intended to strengthen our financial position and outlook, including a reduction in our quarterly distribution.

The amount of cash we are able to distribute depends on the amount of cash we generate from our operations, which can fluctuate quarterly based upon a number of factors, including:

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the operating performances of our assets;

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commodity prices;

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our ability to bring new assets into service at its expected time and projected cost;

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actions of governmental regulatory bodies;

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the level of capital expenditures we make;

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the amount of cash reserves established by Enbridge Management;

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our ability to access capital markets and borrow money;

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our debt service requirements and restrictions in our credit agreements;

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fluctuations in our working capital needs; and

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•

the cost of acquisitions; and

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actions of regulators.

In addition, the amount of cash we distribute depends primarily on our cash flow rather than net income or net loss. Therefore, we may make cash distributions for periods in which we record net losses or may make no distributions for periods in which we record net income. Other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to declare quarterly cash distributions, and our General Partner has considerable discretion to determine the amount of our available cash each quarter. In addition, our General Partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly.

OUR ACTUAL CONSTRUCTION AND DEVELOPMENT COSTS COULD EXCEED OUR FORECAST, AND OUR CASH FLOW FROM CONSTRUCTION AND DEVELOPMENT PROJECTS MAY NOT BE IMMEDIATE, WHICH MAY LIMIT OUR ABILITY TO MAINTAIN OR INCREASE CASH DISTRIBUTIONS.

Our strategy contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets. The construction of new assets involves numerous regulatory, environmental, legal, political, federal, state and local permitting, material and labor cost and operational risks that are difficult to predict and beyond our control. As a result, we may not be able to complete our projects at the costs currently estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

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using cash from operations;

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delaying other planned projects;

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incurring additional indebtedness; or

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issuing additional equity.

Any or all of these methods may not be available when needed or may adversely affect our future results of operations and cash flows.

Our revenues and cash flows may not increase immediately on our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. In addition, circumstances may occur from time to time, such as the inability to obtain a necessary permit, which could cause us to cancel a project. If our revenues and cash flow do not increase at projected levels because of substantial unanticipated delays, project cancellations or other factors, we may not meet our obligations as they become due, and we may need to reduce or re-prioritize our capital budget, sell non-strategic assets, access the capital markets or reassess our level of distributions to unitholders to meet our capital and other requirements.

OUR ABILITY TO ACCESS CAPITAL AND CREDIT MARKETS ON ATTRACTIVE TERMS TO OBTAIN FUNDING FOR OUR CAPITAL PROJECTS AND ACQUISITIONS MAY BE LIMITED.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as the depressed levels of commodity prices experienced since the fall of 2014, can result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, our ability to raise capital through equity or debt offerings. Additionally, the availability and cost of obtaining credit commitments from lenders can change as economic conditions and banking regulations reduce the credit that lenders have available or are willing to lend. These conditions, can make it difficult to obtain funding for our capital needs from the capital markets on acceptable economic terms. As a result, we may be required to revise the timing and scope of capital projects as necessary to adapt to prevailing market and economic conditions.

Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or capital markets on acceptable terms, if needed and to the extent required. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plan, enhance our existing business, complete acquisitions and construction projects, take advantage of business

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opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

A DOWNGRADE IN OUR CREDIT RATING COULD REQUIRE US TO PROVIDE COLLATERAL FOR OUR HEDGING LIABILITIES AND NEGATIVELY IMPACT OUR INTEREST COSTS AND BORROWING CAPACITY UNDER OUR CREDIT FACILITIES.

Standard & Poor’s Global Ratings (S&P), Dominion Bond Rating System (DBRS) and Moody’s Investors Service Inc., (Moody’s) rate our non-credit enhanced, senior unsecured debt. Although we are not aware of current plans by the ratings agencies to lower their respective ratings on such debt, we cannot be assured that such credit ratings will not be downgraded.

Currently, we are parties to certain International Swaps and Derivatives Association, Inc., (ISDA®) agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA® agreements require us to provide assurances of performance if our counterparties’ exposure to us exceeds certain levels or thresholds. We generally provide letters of credit to satisfy such requirements. No letters of credit were provided as of December 31, 2017 as assurances of performance for our then outstanding derivative financial instruments. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by S&P and Moody’s, we would be required to provide letters of credit in substantially greater amounts to satisfy the requirements of our ISDA® agreements. For example, if our credit ratings had been at the lowest level of investment grade at December 31, 2017, we would have been required to provide additional letters of credit in the aggregate amount of $12 million. The amounts of any letters of credit we would have to establish under the terms of our ISDA® agreements would reduce the amount that we are able to borrow under our Credit Facilities.

OUR ACQUISITION STRATEGY MAY BE UNSUCCESSFUL IF WE INCORRECTLY PREDICT THE OPERATING RESULTS OF ACQUIRED ASSETS, ARE UNABLE TO IDENTIFY AND COMPLETE FUTURE ACQUISITIONS OR DO NOT SUCCESSFULLY INTEGRATE ACQUIRED ASSETS OR BUSINESSES.

The acquisition of complementary energy delivery assets is a component of our strategy. Acquisitions present various risks and challenges, including:

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the risk of incorrect assumptions regarding the future results of the acquired operations or expected cost reductions or other synergies expected to be realized as a result of acquiring such operations;

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a decrease in liquidity as a result of utilizing significant amounts of available cash or borrowing capacity to finance an acquisition;

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the loss of critical customers or employees at the acquired business;

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the assumption of unknown liabilities for which we are not fully and adequately indemnified;

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the risk of failing to effectively integrate the operations or management of acquired assets or businesses or a significant delay in such integration; and

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diversion of management’s attention from existing operations.

In addition, we may be unable to identify acquisition targets or consummate acquisitions in the future.

OUR FINANCIAL PERFORMANCE COULD BE ADVERSELY AFFECTED IF OUR PIPELINE SYSTEMS ARE USED LESS.

Our financial performance depends to a large extent on the volumes transported on our liquids pipeline systems. Decreases in the volumes transported by our systems can directly and adversely affect our revenues and results of operations. The volume transported on our pipelines can be influenced by factors beyond our control including:

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competition;

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regulatory action;

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weather conditions;

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storage levels;

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alternative energy sources;

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decreased demand;

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fluctuations in energy commodity prices;

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•

environmental or other governmental regulations;

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shareholder activism or activities by non-governmental organization to restrict the exploration, development or production of crude oil by our customers;

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economic conditions;

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supply disruptions;

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availability of supply connected to our pipeline systems; and

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availability and adequacy of infrastructure to move, treat and refine supply into and out of our systems.

As an example, the volume of shipments on our Lakehead System depends heavily on the supplies of western Canadian crude oil. Insufficient supplies of western Canadian crude oil that limit shipments on our Lakehead System, which occurred in mid-2016 due to extreme wildfires in northeastern Alberta, will adversely affect our business. Decreases in crude oil exploration and production activities in western Canada and other factors, including supply disruption, higher development costs and competition, could reduce volumes transported growth of our Lakehead System. The volume of crude oil that we transport on our Lakehead System, as well as the North Dakota and Bakken Systems, also depends on the demand for crude oil in the Great Lakes and Midwest regions of the United States and the volumes of crude oil and refined products delivered by others into these regions and the province of Ontario. As well, there are supply driven risks around our North Dakota and Bakken System, as lower commodity prices can reduce drilling and result in decrease volumes on our systems.

In addition, our ability to increase deliveries to expand our Lakehead System in the future depends on increased supplies of western Canadian crude oil. We expect that any potential growth in future supplies of western Canadian crude oil will come from the development of oil sands projects in Alberta. Full utilization of additional capacity as a result of our Alberta Clipper and Southern Access pipelines and future expansions of our Lakehead System will largely depend on these anticipated increases in crude oil production from oil sands projects. A reduction in demand for crude oil or a decline in crude oil prices may make certain oil sands projects uneconomical since development costs for production of crude oil from oil sands are greater than development costs for production of conventional crude oil. Oil sands producers may cancel or delay plans to expand their facilities, as some oil sands producers have done in recent years, if crude oil prices are at levels that do not support expansion. Any cancellation or delay of oil sands projects could directly impact our Lakehead System with potential indirect impacts on our Mid-Continent, North Dakota and Bakken Systems. Additionally, measures adopted by the government of the province of Alberta to increase its share of revenues from oil sands development coupled with a decline in crude oil prices could reduce the volume growth we have anticipated in expanding the capacity of our crude oil pipelines.

OUR FINANCIAL PERFORMANCE MAY BE ADVERSELY AFFECTED BY RISK ASSOCIATED WITH THE ALBERTA OIL SANDS.

Our Lakehead System is highly dependent on sustained production from the Alberta oil sands. Alberta oil sands producers face a number of challenges that must be managed effectively to allow for sustained growth in the sector. Factors and risks affecting the oil sands industry include:

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reduced crude oil prices;

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cost inflation;

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labor availability;

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environmental and regulatory impact;

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reputation management;

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changing policy and regulation; and

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commodity price volatility.

Adverse developments or trends involving these and other related factors could affect oil sands development or production levels and result in decreased volumes on the Lakehead System, and our failure to effectively anticipate, manage or respond to these risks could result in significant capital expenditures or increased operating costs or otherwise negatively affect our operating results or financial condition.

COMPETITION MAY REDUCE OUR REVENUES.

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Our Lakehead System faces current and potentially future competition from other pipelines for transporting western Canadian crude oil, which may reduce our volumes and the associated revenues. Lower volumes will increase our transportation rates where those rates are determined using a cost-of-service methodology, and higher rates may result in even greater competitive pressure from these competing pipelines and such increases in transportation rates could result in rates that are higher than competitive conditions will otherwise permit. In addition, our Lakehead System competes with other crude oil and refined product pipelines and other methods of delivering crude oil and refined products to the refining centers of Minneapolis-St. Paul, Chicago, Detroit, Toledo, Buffalo, and Sarnia, and the refinery market and pipeline hub located in the Patoka/Wood River area of southern Illinois. Refineries in the markets served by our Lakehead System compete with refineries in western Canada, the province of Ontario and the Rocky Mountain region of the United States for supplies of western Canadian crude oil.

Volatility in commodity prices can impact production volumes in the oil sands region of western Canada and the Bakken region of North Dakota, our two primary crude oil supply basins.

The relatively high costs and large up front capital investments required by oil sands projects involves significant assumptions concerning short-term and long-term crude oil fundamentals including world supply and demand, North American supply and demand, and price outlook among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. These decisions may impact the annual rate of future supply growth from the oil sands region.

While current oil sands projects are not as sensitive to short-term declines in crude oil prices, a protracted decline in crude oil prices, such as has been experienced since the fall of 2014, could result in delay or cancellation of future projects. In addition, wide commodity price spreads have impacted producer netbacks and margins in the past years that largely resulted from insufficient pipeline infrastructure and takeaway capacity from producing regions in Alberta. Combined with high labor and operating costs, this has forced some producers to reconsider or defer projects until a more favorable climate for infrastructure development can be forecast.

Tight sands and shale oil production in any basin in North America such as the Bakken or the Permian will be comparatively more sensitive to the short-term changes in crude oil prices due to the sharp declining production profile associated with individual tight sands and shale oil wells. Accordingly, during periods of comparatively low prices, supply growth from the North Dakota basin may be lower, which may impact volumes on our pipeline system including impacts on our minority stake on the Bakken Pipeline System, which consists of DAPL and ETCOP.

WE FACE RISKS ASSOCIATED WITH ACTIONS TAKEN IN CONNECTION WITH OUR STRATEGIC REVIEW.

Our previously announced strategic review was completed in April 2017. In connection with the completion of our strategic review, the following actions were taken in an effort to strengthen our financial position and outlook:

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the reduction of our quarterly distributions from $0.583 per unit to $0.35 per unit;

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the sale of our Midcoast gas gathering the processing business to our General Partner;

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the finalization of the joint funding arrangement with our General Partner for our investment in the Bakken Pipeline System;

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the redemption of Series 1 Preferred Units held by our General Partner and the repayment of the deferred distribution balance owned to our General Partner and;

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the restructuring of our capital structure and modification of our incentive distribution rights through the irrevocable waiver by a wholly-owned subsidiary of our General Partner of all of that subsidiary's Class D units and Incentive Distribution Units (IDUs) for new Class F units.

There can be no assurance that the actions we took as a result of our strategic review will be successful or deliver their anticipated benefits. We may be exposed to new and unforeseen risks and challenges, and it may be difficult to predict the success of such endeavors or the impacts to our unit holders.

CHANGES IN, OR CHALLENGES TO, OUR RATES COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies, or both. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates, the profitability of our pipeline businesses would suffer.

Under current policy, the FERC permits interstate pipelines that are subject to cost of service regulation to include an income tax allowance when calculating their regulated rates. The FERC’s income tax allowance policy has been the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. On December 15, 2016, the FERC issued a Notice of Inquiry (NOI) requesting energy industry input on how the FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a MLP. The FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC’s jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. The FERC issued the NOI in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a Return on Equity (ROE) calculated on a pre-tax basis. We cannot predict whether the FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether the FERC will modify its current policy on either income tax allowances or ROE calculations for pipeline companies organized as part of a MLP. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a MLP or decreases the ROE for such pipelines could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates.

Effective January 2018, the United States legislation referred to as the Tax Cuts and Jobs Act (the TCJA) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. This tax rate change is expected to cause us to reduce the income tax allowance component of tolls in our FERC regulated cost-of-service based Facility Surcharge Mechanism (FSM) projects. Impacts of tax reform will be reflected in Lakehead's FSM toll filing for rates effective April 1, 2018. Further, there is a risk that our other FERC regulated pipelines may be required to lower their transportation rates to reflect the TCJA. This risk could materialize through either a FERC initiated requirement or through a shipper seeking to have the rates of a specific pipeline reduced.

We believe that the rates we charge for transportation services on our interstate common carrier pipelines are just and reasonable under the ICA. However, because the rates that we charge are subject to review upon an appropriately supported protest or complaint, or a regulator’s own initiative, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations. Competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so.

INCREASED REGULATION AND REGULATORY SCRUTINY MAY REDUCE OUR REVENUES.

Our interstate pipelines are subject to FERC regulation of terms and conditions of service. Action by the FERC on currently pending regulatory matters, including the FERC’s proposed changes issued on October 20, 2016, in Docket No. RM17-1, as well as matters arising in the future could adversely affect our ability to establish or charge rates that would increase revenues and cover future costs. Specifically, in Docket No. RM17-1, the FERC proposes a new policy that would deny proposed index increases if a pipeline’s Form No. 6 reflects revenues that exceed the total cost-of-service by fifteen percent for both of the prior two years or if the proposed index increases exceed by five percent the annual cost changes reported on the pipeline’s most recently filed Form 6. Additionally, in that proceeding, the FERC proposes to require pipelines to provide more specific data on its Form 6. The Commission has not issued an order on these proposals, but such changes could result in an adverse impact on our ability to increase FERC regulated rates and accordingly revenues associated with the transportation and storage services we provide pursuant to indexed-based rates. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates.

OUR RISK MANAGEMENT POLICIES CANNOT ELIMINATE ALL RISK. IN ADDITION, ANY NON-COMPLIANCE WITH OUR RISK MANAGEMENT POLICIES COULD RESULT IN SIGNIFICANT FINANCIAL LOSSES.

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We use derivative financial instruments to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could result in significant financial losses and have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

COMPLIANCE WITH ENVIRONMENTAL AND OCCUPATIONAL SAFETY LAWS AND REGULATIONS MAY EXPOSE US TO SIGNIFICANT COSTS AND LIABILITIES.

Our crude oil and liquid petroleum gathering, transportation and storage operations are subject to foreign, federal, state, provincial and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, oftentimes imposing stringent requirements and necessitating capital expenditures or increased operating costs to achieve compliance, especially when activity is in the presence of environmentally sensitive receptors such as water crossings, wetlands and endangered species. Our failure to comply with these laws, regulations and operating permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations or the occurrence of delays in the permitting or performance of projects and the issuance of injunctions limiting or preventing some or all of our operations. Our operation of liquid petroleum gathering, storage and transportation facilities exposes us to the risk of incurring significant environmental and safety-related costs and liabilities. Additionally, operational modifications, including pipeline restrictions, necessary to comply with regulatory requirements and resulting from our handling of crude oil and liquid petroleum, historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or occupational safety and health incidents can also result in significant cost or limit revenues and volumes. Further, environmental and occupational safety laws and regulations, including but not limited to pipeline safety, wastewater discharge and air emission requirements, continue to become more stringent over time, particularly those related to the oil and gas industry. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of liquid petroleum and crude oil and wastes on, under or from our properties and facilities, many of which have been used for gathering or storage activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our liquid petroleum and crude oil or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

Moreover, public interest in the protection of the environment has increased dramatically in recent years and the trend of more expansive and stringent environmental legislation and regulations applied to the hazardous liquid transportation, gathering and storage industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, in October 2015, the EPA issued a final rule under the federal CAA, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone to 70 parts per billion under both the primary and secondary standards.

The EPA published a final rule in November 2017 with attainment designations for only some areas, with other designations to be announced at a later date. State implementation of these revised standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In a second example, in June 2015, the EPA and the Army Corps issued a new rule to clarify the federal jurisdictional reach over waters of the United States. The rule has been challenged in numerous courts on the grounds that it unlawfully expands the reach of the Clean Water Act. The United States Sixth Circuit Court of Appeals stayed implementation of the rule nationwide in October 2015 pending review, but on January 22, 2018, the United States Supreme Court held that legal challenges to the rule must first be heard at the district court level rather than the appellate court level. Additionally, following the issuance of a presidential executive order to review the rule, the EPA and the Army Corps proposed a rulemaking to repeal the rule in June 2017. The EPA and Army Corps also announced their intent to issue a new rule defining the reach of federal jurisdiction. On February 6, 2018 the EPA and Army Corps issued a final rule amending the effective date of the 2015 rule to February 6, 2020. Challenges to this rule have been filed and remain pending in various federal courts. As a result, future

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implementation of the rule is uncertain at this time. If the June 2015 rule is implemented, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas and water crossings in connection with any expansion activities. We may not be able to recover these costs of compliance from insurance or through higher rates.

THE ADOPTION AND IMPLEMENTATION OF CLIMATE CHANGE LEGISLATION OR REGULATIONS RESTRICTING EMISSIONS OF GREENHOUSE GASES MAY EXPOSE US TO SIGNIFICANT COSTS AND LIABILITIES.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, federal, state and provincial levels of government to monitor and limit emissions of greenhouse gases (GHGs), which include carbon dioxide and methane. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the United States federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of the federal CAA that, among other things, establish Potential for Significant Deterioration (PSD) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum system sources in the United States, including, among others, onshore and offshore production and onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil industry, including gathering, compression and boosting facilities as well as completions and workovers from hydraulically fractured oil wells, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the new source performance standards. The EPA also has begun directly regulating emissions of methane, a GHG, from oil and natural gas operations, commencing with a final rule in 2012 establishing new source performance standards known as Subpart OOOO on certain equipment and processes and expanding those requirements in 2016 with added new source performance standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions. On April 19, 2017, however, the EPA announced its intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions for 90 days. Petitioners challenged the administrative stay in the D.C. Circuit, and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed rules effective. The EPA also proposed a rule-making in June 2017 to stay the methane rules for two years and to revisit their implementation in their entirety. These methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking in the future, which action is also likely to be challenged in the courts.

On the international level, in December 2015, the United States was one of many countries at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years. The Paris Agreement was signed by the United States in April 2016 and entered into force in November 2016; however, in August 2017, the United States State Department officially informed the United Nations of the intent of the United States to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain United States city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.

The adoption and implementation of any international, federal, state or provincial legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas, which could reduce volumes on our pipeline systems. One or more of these developments could have an adverse effect on our business, financial condition and results of operation. Additionally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continued

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to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

LAWS AND REGULATIONS REGARDING HYDRAULIC FRACTURING COULD RESULT IN REDUCTIONS OR DELAYS IN PRODUCTION ACTIVITIES BY OUR CUSTOMERS THAT MAY REDUCE OUR REVENUES DUE TO DECREASED VOLUMES TRANSPORTED ON OUR PIPELINES.

Hydraulic fracturing is an essential and common practice used to stimulate production of crude oil from dense subsurface rock formations such as shales. Many of our customers routinely apply hydraulic-fracturing techniques in many of their United States onshore crude oil drilling and completion programs. The process involves the injection of water, sand or alternative proppant and chemical additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production.

Hydraulic fracturing is typically regulated by state oil commissions and similar agencies. However, several federal agencies have also asserted regulatory authority over certain aspects of the process. For example, in 2014, the EPA asserted regulatory authority under the Safe Drinking Water Act’s Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Additionally, the Bureau of Land Management (BLM) published a final rule in 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian land. This rule has been the subject of re-review and litigation and, most recently, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule. The timing of a final rulemaking that would rescind the 2015 rule is uncertain and as a result of these developments and likely legal challenges, future implementation of the BLM rule is uncertain at this time. Also, from time to time, legislation has been introduced, but not enacted, in the United States Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, a number of federal entities have reviewed various environmental issues associated with hydraulic fracturing with, for example, the EPA releasing a final report on the potential impacts of hydraulic fracturing on drinking water resources in December 2016, with the report concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Certain states where our infrastructure is used by our customers, have adopted and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, or other regulatory requirements on hydraulic-fracturing operations, including subsurface water disposal. States also could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. In the event that new federal restrictions on the hydraulic fracturing process are adopted in areas where our customers operate, those customers may incur significant additional costs or permitting requirements to comply with such federal requirements, and could experience added delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for our services and have a material adverse effect on our business, financial condition and results of operations.

Operation of complex pipeline systems, gathering and storage operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. In addition, we could be subject to significant fines and penalties from regulators in connection with such events. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these catastrophic events could be greater.

OUR ASSETS VARY IN AGE AND WERE CONSTRUCTED OVER MANY DECADES WHICH MAY CAUSE OUR INSPECTION, MAINTENANCE AND REPAIR COSTS TO INCREASE IN THE FUTURE. IN ADDITION, THERE COULD BE SERVICE INTERRUPTIONS DUE TO UNKNOWN EVENTS OR CONDITIONS, OR INCREASED DOWNTIME ASSOCIATED WITH OUR PIPELINES THAT COULD HAVE A MATERIAL AND ADVERSE EFFECT ON OUR BUSINESS AND RESULTS OF OPERATIONS.

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Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make distributions to our unitholders. Additionally, there could be service interruptions due to unknown events or conditions, or increased downtime associated with our pipelines that could have a material and adverse effect on our business and financial results.

MEASUREMENT ADJUSTMENTS ON OUR PIPELINE SYSTEM CAN BE MATERIALLY IMPACTED BY CHANGES IN ESTIMATION, COMMODITY PRICES AND OTHER FACTORS.

Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum pipelines. The three types of oil measurement adjustments that routinely occur on our systems include:

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physical, which results from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;

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degradation resulting from mixing at the interface within our pipeline systems or terminals and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and

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revaluation, which is a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers.

Quantifying oil measurement adjustments is inherently difficult because physical measurements of volumes are not practical as products continuously move through our pipelines and virtually all of our pipeline systems are located underground. In our case, measuring and quantifying oil measurement losses is especially difficult because of the length of our pipeline systems and the number of different grades of crude oil and types of crude oil products we transport. Accordingly, we utilize engineering-based models and operational assumptions to estimate product volumes in our system and associated oil measurement losses.

WE DO NOT OWN A MAJORITY OF THE LAND ON WHICH OUR PIPELINES ARE LOCATED, WHICH COULD RESULT IN INCREASED COSTS AND DISRUPTIONS TO OUR OPERATIONS.

We do not own a majority of the land on which our pipelines are located; as a result, we are subject to the possibility of more onerous terms and increased costs to retain necessary land use or we could be required to re-route portions of our pipelines if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies (including but not limited to Native American lands), and some of our agreements may grant us those rights for only a specific period of time. We are unable to predict the outcome of discussions with third parties, the governmental agencies, the appropriate Native American tribes, the tribes’ governing bodies, or the United States Bureau of Indian Affairs with respect to future arrangements or changes in applicable laws and the resulting costs, fees, bonds and taxes related to these leases, easements and rights-of-way, or grants of land rights. In the context of certain types of allotted lands owned by Native American tribes or formerly owned by individual Indian landowners, a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals held that tribal ownership of even a very small fractional interest in allotted land bars condemnation of any interest in the allotment. Consequently, in such scenarios, we would be unable to condemn such allotted lands in order to expand operations or to obtain pipeline rights-of-way where the existing rights-of-way may soon lapse or terminate. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way on favorable terms or without experiencing significant delayed and costs. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, and financial position.

In addition, our industry is subject to activism and activities by non-governmental organizations seeking to restrict the exploration, development and production of crude oil by our customers generally and by oil sands producers in particular. These activists and organizations as well as others concerned with environmental impacts of pipeline routes have used political pressure to influence the timing of and whether such permits are granted which could impact future pipeline development. Our loss of these rights, through our inability to obtain or renew right-of-way contracts or otherwise, could interfere with or block expansion or development projects and could have a material adverse effect on our business, financial condition, results of operations and our ability to make cash distributions to our unitholders.

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TERRORIST ATTACKS AND THREATS, ESCALATION OF MILITARY ACTIVITY IN RESPONSE TO THESE ATTACKS OR ACTS OF WAR, AND OTHER CIVIL UNREST OR ACTIVISM COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced volumes on our pipeline systems, denial or delay of permits and rights-of-way and additional legislative or regulatory burdens. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

CYBER-ATTACKS OR SECURITY BREACHES COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Our business is dependent upon information systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. We conduct cyber security audits from time to time and continuously monitor our systems in an effort to mitigate the risk of cyber-attacks or security breaches. Enbridge has a Cybersecurity controls framework in place which has been derived from the NIST Cybersecurity Framework and ISO 27001 standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a 7X24 security operations center to monitor, detect and investigate any anomalous activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed. Despite our security measures, our information systems may become the target of cyber-attacks or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems and result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. Enbridge's current insurance coverage programs do not contain specific coverage for cyber-attacks or security breaches. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.

WE ARE EXPOSED TO CREDIT RISKS OF OUR CUSTOMERS, AND ANY MATERIAL NONPAYMENT OR NONPERFORMANCE BY OUR KEY CUSTOMERS COULD ADVERSELY AFFECT OUR CASH FLOW AND RESULTS OF OPERATIONS.

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

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OUR PIPELINE SAFETY AND PIPELINE INTEGRITY PROGRAMS MAY IMPOSE SIGNIFICANT COSTS AND LIABILITIES ON US, WHILE INCREASED REGULATORY REQUIREMENTS RELATED TO THE INTEGRITY OF OUR PIPELINE SYSTEMS MAY REQUIRE US TO SPEND ADDITIONAL MONEY TO COMPLY WITH SUCH REQUIREMENTS.

Certain of our pipelines are subject to regulation by the federal PHMSA under the Hazardous Liquid Pipeline Safety Act (HLPSA) with respect to crude oil, as has been amended by the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act). The HLPSA governs the design, installation, testing, construction, operation, replacement and management of crude oil pipeline facilities.

These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in High Consequence Areas (HCAs), such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. These rules require operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

The HLPSA was amended by the 2011 Pipeline Safety Act which became law in January 2012. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements, including periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. This final rule has not, however, been published in the Federal Register. The Office of Management & Budget’s Office of Information and Regulatory Affairs’ Unified Regulatory Agenda projects publication of the final rule in the first half of 2018, but the timing for implementation of this rule remains uncertain. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs or operational delays that could have a material adverse effect on our results of operations or financial position.

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Additionally, effective April 2017, PHMSA adopted a final rule increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $209,002 per violation per day and up to $2,090,022 for a related series of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE AND RELATIONSHIPS WITH OUR GENERAL PARTNER AND ENBRIDGE MANAGEMENT

THE INTERESTS OF ENBRIDGE MAY DIFFER FROM OUR INTERESTS AND THE INTERESTS OF OUR UNITHOLDERS, AND THE BOARD OF DIRECTORS OF ENBRIDGE MANAGEMENT MAY CONSIDER THE INTERESTS OF ALL PARTIES TO A CONFLICT, NOT JUST THE INTERESTS OF OUR UNITHOLDERS, IN MAKING IMPORTANT BUSINESS DECISIONS.

Enbridge indirectly owns all of the shares of our General Partner and all of the voting shares of Enbridge Management, and elects all of the directors of both companies. Furthermore, some of the directors and officers of our General Partner and Enbridge Management are also directors and officers of Enbridge. Consequently, conflicts of interest could arise between our unitholders and Enbridge.

Our partnership agreement limits the fiduciary duties of our General Partner to our unitholders. These restrictions allow our General Partner to resolve conflicts of interest by considering the interests of all of the parties to the conflict, including Enbridge Management’s interests, our interests and those of our General Partner. In addition, these limitations reduce the rights of our unitholders under our partnership agreement to sue our General Partner or Enbridge Management, its delegate, should its directors or officers act in a way that, were it not for these limitations of liability, would constitute breaches of their fiduciary duties.

We do not have any employees. In managing our business and affairs, we rely on employees of Enbridge, and its affiliates, who act on behalf of and as agents for us. A decrease in the availability of employees from Enbridge could adversely affect us.

OUR PARTNERSHIP AGREEMENT AND THE DELEGATION OF CONTROL AGREEMENT LIMIT THE FIDUCIARY DUTIES THAT ENBRIDGE MANAGEMENT AND OUR GENERAL PARTNER OWE TO OUR UNITHOLDERS AND RESTRICT THE REMEDIES AVAILABLE TO OUR UNITHOLDERS FOR ACTIONS TAKEN BY ENBRIDGE MANAGEMENT AND OUR GENERAL PARTNER THAT MIGHT OTHERWISE CONSTITUTE A BREACH OF A FIDUCIARY DUTY.

Our partnership agreement contains provisions that modify the fiduciary duties that our General Partner would otherwise owe to our unitholders under state fiduciary duty law. Through the delegation of control agreement, these modified fiduciary duties also apply to Enbridge Management as the delegate of our General Partner. For example, our partnership agreement:

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permits our General Partner to make a number of decisions, including the determination of which factors it will consider in resolving conflicts of interest, in its “sole discretion.” This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;

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provides that any standard of care and duty imposed on our General Partner will be modified, waived or limited as required to permit our General Partner to act under our partnership agreement and to make any decision pursuant to the authority prescribed in our partnership agreement, so long as such action is reasonably believed by the General Partner to be in our best interests; and

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provides that our General Partner and its directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions if they acted in good faith.

These and similar provisions in our partnership agreement may restrict the remedies available to our unitholders for actions taken by Enbridge Management or our General Partner that might otherwise constitute a breach of a fiduciary duty.

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POTENTIAL CONFLICTS OF INTEREST MAY ARISE AMONG ENBRIDGE AND ITS SHAREHOLDERS, ON THE ONE HAND, AND US AND OUR UNITHOLDERS AND ENBRIDGE MANAGEMENT AND ITS SHAREHOLDERS, ON THE OTHER HAND. BECAUSE THE FIDUCIARY DUTIES OF THE DIRECTORS OF OUR GENERAL PARTNER AND ENBRIDGE MANAGEMENT HAVE BEEN MODIFIED, THE DIRECTORS MAY BE PERMITTED TO MAKE DECISIONS THAT BENEFIT ENBRIDGE AND ITS SHAREHOLDERS OR ENBRIDGE MANAGEMENT AND ITS SHAREHOLDERS MORE THAN US AND OUR UNITHOLDERS.

Conflicts of interest may arise from time to time among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Conflicts of interest may also arise from time to time between us and our unitholders, on the one hand, and Enbridge Management and its shareholders, on the other hand. In managing and controlling us as the delegate of our General Partner, Enbridge Management may consider the interests of all parties to a conflict and may resolve those conflicts by making decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders. The following decisions, among others, could involve conflicts of interest:

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whether we or Enbridge will pursue certain acquisitions or other business opportunities;

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whether we will issue additional units or other equity securities or whether we will purchase outstanding units;

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whether we or Enbridge Management will issue additional shares or other equity securities;

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the amount of payments to Enbridge and its affiliates for any services rendered for our benefit;

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the amount of costs that are reimbursable to Enbridge Management or Enbridge and its affiliates by us;

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the enforcement of obligations owed to us by Enbridge Management, our General Partner or Enbridge, including obligations regarding competition between Enbridge and us; and

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the retention of separate counsel, accountants or others to perform services for us and Enbridge Management.

In these and similar situations, any decision by Enbridge Management may benefit one group more than another, and in making such decisions, Enbridge Management may consider the interests of all groups, as well as other factors, in deciding whether to take a particular course of action.

In other situations, Enbridge may take certain actions, including engaging in businesses that compete with us or are adverse to us and our unitholders. For example, although Enbridge and its subsidiaries are generally restricted from engaging in any business that is in direct material competition with our businesses, that restriction is subject to the following significant exceptions:

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Enbridge and its subsidiaries are not restricted from continuing to engage in businesses, including the normal development of such businesses, in which they were engaged at the time of our initial public offering in December 1991;

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such restriction is limited geographically only to those routes and products for which we provided transportation at the time of our initial public offering;

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Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us as part of a larger acquisition, so long as the majority of the value of the business or assets acquired, in Enbridge’s reasonable judgment, is not attributable to the competitive business; and

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Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us if that business is first offered for acquisition to us and the board of directors of Enbridge Management and our unitholders determine not to pursue the acquisition.

As a result of these exceptions, Enbridge and its subsidiaries would be permitted to transport crude oil and liquid petroleum over routes that are not the same as our Lakehead System, even if such transportation is in direct material competition with our business.

AFFILIATES OF OUR GENERAL PARTNER ARE NOT LIMITED IN THEIR ABILITY TO COMPETE WITH US, WHICH COULD LIMIT COMMERCIAL ACTIVITIES OR OUR ABILITY TO ACQUIRE ADDITIONAL ASSETS OR BUSINESSES.

Affiliates of our General Partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Enbridge and its affiliates may acquire, construct or dispose of additional transmission, storage and gathering or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the midstream

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energy business and each has significantly greater resources and experience than we have, which may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely affect our results of operations and available cash.

WE CAN ISSUE ADDITIONAL COMMON OR OTHER CLASSES OF UNITS, INCLUDING ADDITIONAL i-UNITS TO ENBRIDGE MANAGEMENT WHEN IT ISSUES ADDITIONAL SHARES, WHICH WOULD DILUTE THE OWNERSHIP INTEREST OF OUR UNITHOLDERS.

The issuance of additional common or other classes of units by us, including the issuance of additional i-units to Enbridge Management when it issues additional shares may have the following effects:

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The amount available for distributions on each unit may decrease;

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The relative voting power of each previously outstanding unit may decrease; and

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The market price of the Class A common units may decline.

Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units or Class E units that it or its subsidiary currently owns could reduce the market price of the Class A common units. Our partnership agreement allows the General Partner to cause us to register for public sale any units held by the General Partner or its affiliates. A public or private sale of the Class A or Class B common units or Class E units currently held by our General Partner or its subsidiary could absorb some of the trading market demand for the outstanding Class A common units.

HOLDERS OF OUR LIMITED PARTNER INTEREST HAVE LIMITED VOTING RIGHTS.

Our unitholders have limited voting rights on matters affecting our business, which may have a negative effect on the price at which our common units trade. In particular, the unitholders did not elect our General Partner or the directors of our General Partner or Enbridge Management and have no rights to elect our General Partner or the directors of our General Partner or Enbridge Management on an annual or other continuing basis. Furthermore, if unitholders are not satisfied with the performance of our General Partner, they may find it difficult to remove our General Partner. Under the provisions of our partnership agreement, our General Partner may be removed upon the vote of at least 66.67% of the outstanding common units (excluding the units held by the General Partner and its affiliates) and a majority of the outstanding i-units voting together as a separate class (excluding the number of i-units corresponding to the number of shares of Enbridge Management held by our General Partner and its affiliates). Such removal must, however, provide for the election and succession of a new general partner, who may be required to purchase the departing general partner interest in us in order to become the successor general partner. Such restrictions may limit the flexibility of the limited partners in removing our general partner, and removal may also result in the general partner interest in us held by the departing general partner being converted into Class A common units.

THE NYSE DOES NOT REQUIRE A PUBLICLY-TRADED PARTNERSHIP LIKE US TO COMPLY WITH CERTAIN OF ITS CORPORATE GOVERNANCE REQUIREMENTS.

Our Class A common units are listed on the NYSE. The NYSE does not require us to have, and we do not intend to have, a majority of independent directors on the boards of our General Partner or Enbridge Management, or to establish a compensation committee or nominating and corporate governance committee. In addition, any future issuance of additional Class A common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, holders of our Class A common units will not have the same protections afforded to shareholders of most corporations that are subject to all of the NYSE corporate governance requirements.

WE ARE A HOLDING COMPANY AND DEPEND ENTIRELY ON OUR OPERATING SUBSIDIARIES' DISTRIBUTIONS TO SERVICE OUR DEBT OBLIGATIONS.

We are a holding company with no material operations. If we cannot or do not receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations. Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions, which could further limit each operating subsidiaries’ ability to make distributions to us.

The debt securities we issue and any guarantees issued by any of our subsidiaries that are guarantors will be structurally subordinated to the claims of the creditors of any of our operating subsidiaries who are not guarantors of

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the debt securities. Holders of the debt securities will not be creditors of our operating subsidiaries who have not guaranteed the debt securities. The claims to the assets of these non-guarantor operating subsidiaries derive from our own ownership interest in those operating subsidiaries. Claims of our non-guarantor operating subsidiaries’ creditors will generally have priority as to the assets of such operating subsidiaries over our own ownership interest claims and will therefore have priority over the holders of our debt, including the debt securities. Our non-guarantor operating subsidiaries’ creditors may include:

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general creditors;

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trade creditors;

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secured creditors;

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taxing authorities; and

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creditors holding guarantees.

ENBRIDGE MANAGEMENT'S DISCRETION IN ESTABLISHING OUR CASH RESERVES GIVES IT THE ABILITY TO REDUCE THE AMOUNT OF CASH AVAILABLE FOR DISTRIBUTION TO OUR UNITHOLDERS.

Enbridge Management may establish cash reserves for us that in its reasonable discretion are necessary to fund our future operating and capital expenditures, provide for the proper conduct of business, and comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves affect the amount of cash available for distribution to holders of our common units.

WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY UNEXPECTED LIABILITIES OR BY THE INABILITY OF OUR INSURERS TO SATISFY OUR CLAIMS.

Our assets and operations are covered under insurance programs maintained by Enbridge for its subsidiaries and affiliates. Enbridge’s comprehensive insurance programs are maintained on a consolidated basis to include the operations of its subsidiaries, including us. We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets occasionally make it more difficult for us to obtain certain types of coverage at reasonable rates and we may elect to self-insure a portion of our asset portfolio. In addition, we do not maintain offshore business interruption insurance. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our cash flows, financial condition and results of operations. In addition, in the event there is a total or partial loss of our assets or storage facilities, any insurance proceeds that we may receive in respect thereof may not be sufficient in any particular situation to effect a restoration of our assets or facilities to the condition that existed prior to such loss or sufficient to satisfy our obligations under the notes. In addition, in the unlikely event that multiple insurable incidents that, in the aggregate, exceed coverage limits and occur within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities covered thereby on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge and other Enbridge subsidiaries.

TOTAL INSURANCE COVERAGE FOR MULTIPLE INSURABLE INCIDENTS EXCEEDING COVERAGE LIMITS WOULD BE ALLOCATED BY OUR GENERAL PARTNER ON AN EQUITABLE BASIS.

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. If multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement the Partnership has entered into with Enbridge, and other Enbridge subsidiaries. As a result, we could be exposed to losses for which insurance coverage is not available.

RISKS RELATED TO OUR DEBT AND OUR ABILITY TO MAKE DISTRIBUTIONS

AGREEMENTS RELATING TO OUR DEBT RESTRICT OUR ABILITY TO MAKE DISTRIBUTIONS, WHICH COULD ADVERSELY AFFECT THE VALUE OF OUR CLASS A COMMON UNITS, AND OUR ABILITY TO INCUR ADDITIONAL DEBT AND OTHERWISE MAINTAIN FINANCIAL AND OPERATING FLEXIBILITY.

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We are prohibited from making distributions to our unitholders during (i) the existence of certain defaults under our Credit Facilities or (ii) during a period in which we have elected to defer interest payments on the Junior Notes, subject to limited exceptions as set forth in the related indenture. Further, the agreements governing our Credit Facilities may prevent us from engaging in transactions or capitalizing on business opportunities that we believe could be beneficial to us by requiring us to comply with various covenants, including the maintenance of certain financial ratios and restrictions on:

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incurring additional debt;

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entering into mergers or consolidations or sales of assets; and

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granting liens.

Although the indentures governing our senior notes do not limit our ability to incur additional debt, they impose restrictions on our ability to enter into mergers or consolidations and sales of all or substantially all of our assets, to incur liens to secure debt and to enter into sale and leaseback transactions. A breach of any restriction under our Credit Facilities or our indentures could permit the holders of the related debt to declare all amounts outstanding under those agreements immediately due and payable and, in the case of our Credit Facilities, terminate all commitments to extend further credit. Any subsequent refinancing of our current debt or any new indebtedness incurred by us or our subsidiaries could have similar or greater restrictions.

UNITHOLDERS MAY HAVE LIABILITY TO REPAY DISTRIBUTIONS THAT WERE WRONGFULLY DISTRIBUTED TO THEM.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our partners if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

TAX RISKS TO COMMON UNITHOLDERS

OUR TAX TREATMENT DEPENDS ON OUR STATUS AS A PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES, AND NOT BEING SUBJECT TO A MATERIAL AMOUNT OF ENTITY-LEVEL TAXATION. IF THE INTERNAL REVENUE SERVICES (IRS), WERE TO TREAT US AS A CORPORATION FOR FEDERAL INCOME TAX PURPOSES, WHICH WOULD SUBJECT US TO ENTITY-LEVEL TAXATION, OR IF WE WERE OTHERWISE SUBJECTED TO A MATERIAL AMOUNT OF ADDITIONAL ENTITY-LEVEL TAXATION FOR STATE TAX PURPOSES, THEN OUR DISTRIBUTABLE CASH FLOW TO OUR UNITHOLDERS WOULD BE SUBSTANTIALLY REDUCED.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a publicly-traded partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

Section 7704 of the Internal Revenue Code of 1986 (the Internal Revenue Code) provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. An exception exists, however, with respect to a publicly-traded partnership for which 90% or more of the gross income for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is qualifying income, we will be taxed as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent tax years. Although we do not believe that we will be treated as a corporation for federal income tax purposes based on our current operations, the IRS could disagree with the positions we take. We have not requested, and do not plan

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to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21% and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.

Imposition of any such taxes may substantially reduce the cash we have available for distribution. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation for state tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

THE TAX TREATMENT OF PUBLICLY-TRADED PARTNERSHIPS OR AN INVESTMENT IN OUR UNITS COULD BE SUBJECT TO POTENTIAL LEGISLATIVE, JUDICIAL, OR ADMINISTRATIVE CHANGES AND DIFFERING INTERPRETATIONS, POSSIBLY ON A RETROACTIVE BASIS.

The present federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing United States federal income tax laws that affect publicly-traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for United States federal income tax purposes.

Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether similar legislative or regulatory changes or other proposals will ultimately be enacted.

On January 24, 2017, the United States Treasury Department issued final regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the “Final Regulations”). The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to qualify as a publicly traded partnership for United States federal income tax purposes. It is possible, however, that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

OUR UNITHOLDERS' SHARE OF OUR INCOME WILL BE TAXABLE TO THEM FOR FEDERAL INCOME TAX PURPOSES EVEN IF THEY DO NOT RECEIVE ANY CASH DISTRIBUTIONS FROM US.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholders allocable share of our taxable income will be taxable to the unitholder. This allocation of taxable income may require the payment of federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from that income.

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IF THE IRS CONTESTS THE FEDERAL INCOME TAX POSITIONS WE TAKE, THE MARKET FOR OUR COMMON UNITS MAY BE ADVERSELY IMPACTED AND THE COST OF ANY IRS CONTEST WILL REDUCE OUR DISTRIBUTABLE CASH FLOW TO OUR UNITHOLDERS.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.

TAX GAINS OR LOSSES ON THE DISPOSITION OF OUR COMMON UNITS COULD BE MORE OR LESS THAN EXPECTED.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the tax basis of the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our common units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of common units if the amount realized on a sale of such common units is less than such unitholder’s adjusted basis in the common units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its common units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of common units.

UNITHOLDERS MAY BE SUBJECT TO LIMITATION ON THEIR ABILITY TO DEDUCT INTEREST EXPENSE INCURRED BY US.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

TAX-EXEMPT ENTITIES FACE UNIQUE TAX ISSUES FROM OWNING OUR COMMON UNITS THAT MAY RESULT IN ADVERSE TAX CONSEQUENCES TO THEM.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (UBTI), and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the UBTI of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset UBTI from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

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NON-UNITED STATES UNITHOLDERS WILL BE SUBJECT TO UNITED STATES TAXES AND WITHHOLDING WITH RESPECT TO THEIR INCOME AND GAIN FROM OWNING OUR UNITS.

Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and a non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-United States unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. If you are a non-United States person, you should consult a tax advisor before investing in our common units.

WE TREAT EACH PURCHASER OF COMMON UNITS AS HAVING THE SAME TAX BENEFITS WITHOUT REGARD TO THE ACTUAL COMMON UNITS PURCHASED. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH COULD RESULT IN MORE TAX TO COMMON UNIT HOLDERS AND MAY ADVERSELY AFFECT THE VALUE OF THE COMMON UNITS.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge could also affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

WE GENERALLY PRORATE OUR ITEMS OF INCOME, GAINS, LOSSES AND DEDUCTION BETWEEN TRANSFERORS AND TRANSFEREES OF OUR UNITS EACH MONTH BASED UPON THE OWNERSHIP OF OUR UNITS ON THE FIRST DAY OF EACH MONTH, INSTEAD OF ON THE BASIS OF THE DATE A PARTICULAR UNIT IS TRANSFERRED. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH COULD CHANGE THE ALLOCATION OF ITEMS OF INCOME, GAINS, LOSSES AND DEDUCTION AMONG OUR UNITHOLDERS.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (the “Allocation Date”) based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A UNITHOLDER WHOSE COMMON UNITS ARE THE SUBJECT OF A SECURITIES LOAN, (FOR EXAMPLE, A LOAN TO A "SHORT SELLER" TO COVER A SHORT SALE OF COMMON UNITS), MAY BE CONSIDERED AS HAVING DISPOSED OF THOSE COMMON UNITS. IF SO, THE UNITHOLDER WOULD NO LONGER BE TREATED FOR TAX PURPOSES AS A PARTNER WITH RESPECT TO THOSE COMMON UNITS DURING THE PERIOD OF THE LOAN AND MAY BE REQUIRED TO RECOGNIZE GAINS OR LOSSES FROM THE DISPOSITION.

Because there are no specific rules governing the United States federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned common units. In that case, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash

35

distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

WE HAVE ADOPTED CERTAIN VALUATION METHODOLOGIES FOR FEDERAL INCOME TAX PURPOSES THAT MAY RESULT IN A SHIFT OF INCOME, GAINS, LOSSES AND DEDUCTION BETWEEN OUR GENERAL PARTNER AND OUR UNITHOLDERS. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH COULD ADVERSELY AFFECT THE VALUE OF THE COMMON UNITS.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gains recognized from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

AS A RESULT OF INVESTING IN OUR COMMON UNITS, UNITHOLDERS MAY BECOME SUBJECT TO STATE AND LOCAL TAXES AND RETURN FILING REQUIREMENTS IN JURISDICTIONS WHERE WE OPERATE OR OWN OR ACQUIRE PROPERTIES.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in several states. Most of these states currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is a unitholder’s responsibility to file all federal, state and local tax returns.

IF THE IRS MAKES AUDIT ADJUSTMENTS TO OUR INCOME TAX RETURNS FOR TAX YEARS BEGINNING AFTER DECEMBER 31, 2017, IT (AND SOME STATES) MAY ASSESS AND COLLECT ANY TAXES, (INCLUDING ANY APPLICABLE PENALTIES AND INTEREST), RESULTING FROM SUCH AUDIT ADJUSTMENTS DIRECTLY FROM US, IN WHICH CASE OUR CASH AVAILABLE FOR DISTRIBUTION TO OUR UNITHOLDERS MIGHT BE SUBSTANTIALLY REDUCED AND OUR CURRENT AND FORMER UNITHOLDERS MAY BE REQUIRED TO INDEMNIFY US IN THE AMOUNT OF ANY TAXES, (INCLUDING ANY APPLICABLE PENALTIES AND INTEREST), RESULTING FROM SUCH AUDIT ADJUSTMENTS THAT WERE PAID ON SUCH UNITHOLDERS' BEHALF.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest in accordance with their interests in us during the tax year under audit pay any resulting taxes (including applicable penalties or interest), there can be no assurance that such election will be practical, permissible or effective in all circumstances and the manner in which the election is made and implemented has yet to be determined. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment,

36

we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us in the amount of any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

ITEM 2. PROPERTIES

Descriptions of our properties and maps depicting the locations of our liquids systems are included in Part I.Item 1. Business.

In general, our systems are located on land owned by others and are operated under perpetual easements and rights-of-way, licenses, leases or permits that have been granted by private land owners, public authorities, railways or public utilities. Our liquids systems have pumping stations, tanks, terminals and certain other facilities that are located on land that is owned by us in fee and/or used by us under easements, licenses, leases or permits.

ITEM 3. LEGAL PROCEEDINGS

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part II.Item 8. Financial Statements and Supplementary Data, under Note 21 - Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference.

BRINCKERHOFF v. ENBRIDGE ENERGY CO., INC. ET AL.

On July 20, 2015, plaintiff Peter Brinckerhoff (the Plaintiff), individually and as trustee of the Peter R. Brinckerhoff Trust, filed a Verified Class Action and Derivative Complaint in the Court of Chancery of the State of Delaware against our General Partner, Enbridge, Enbridge Management, Enbridge Pipelines (Alberta Clipper) L.L.C., the OLP, us, and the following individuals: Jeffrey A. Connelly, Rebecca B. Roberts, Dan A. Westbrook, J. Richard Bird, J. Herbert England, C. Gregory Harper, D. Guy Jarvis, Mark A. Maki, and John K. Whelen, (collectively, the Director Defendants). The initial Complaint asserted both class action claims on behalf of holders of our Class A Common Units, as well as derivative claims brought on behalf of us. The Plaintiff’s claims arose out of the January 2, 2015 repurchase by us of our General Partner’s 66.67% interest in the pipeline that runs from the Canadian international border near Neche, North Dakota to Superior, Wisconsin on our Lakehead System (Alberta Clipper Pipeline), known as the 2015 Transaction. First, the Plaintiff alleged that the 2015 Transaction improperly amended without Public Unitholder consent the Sixth Amended and Restated Agreement of Limited Partnership (the LPA) so as to allocate to the Public Unitholders gross income that should have been allocated to the General Partner (the Special Tax Allocation). Second, the Plaintiff alleged that we paid an unfair price for our General Partner’s 66.67% interest in the Alberta Clipper Pipeline such that the 2015 Transaction breached the LPA because it was not fair and reasonable to the Partnership. The initial Complaint asserted claims for breach of fiduciary duty, breach of the covenant of good faith and fair dealing, breach of residual fiduciary duties, tortious interference, aiding and abetting, and rescission and reformation.

On April 29, 2016, the Court of Chancery granted Enbridge’s and the Director Defendants’ motion to dismiss and dismissed the case in its entirety. On May 26, 2016 the Plaintiff appealed that dismissal to the Delaware Supreme Court. On March 20, 2017, the Delaware Supreme Court reversed in part and affirmed in part the ruling of the Court of Chancery. Specifically, the Delaware Supreme Court affirmed that the enactment of the Special Tax Allocation did not breach the LPA, but reversed on the question of whether the Plaintiff had adequately alleged that the price we paid in the 2015 Transaction, including the Special Tax Allocation component, was fair and reasonable to the Partnership. On November 15, 2017, Plaintiff filed a Verified Second Amended Complaint (the Second Amended Complaint). The Second Amended Complaint added Piper Jaffray & Co. as successor to Simmons & Company International (Simmons) as a direct Defendant. Simmons acted as the financial advisor to our Special Committee in the 2015 Transaction. The Second Amended Complaint also revised many of the allegations against Enbridge and the Director Defendants. All Defendants have moved to dismiss the Second Amended Complaint. The parties are currently in discovery, with trial currently scheduled in the fourth quarter of 2018.

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol “EEP.” The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2017 and 2016 are summarized as follows:

First

Second

Third

Fourth

2017 Quarters

High

$

26.17

$

19.64

$

16.63

$

16.34

Low

$

16.95

$

14.68

$

13.87

$

12.25

Cash distributions paid

$

0.583

$

0.350

$

0.350

$

0.350

2016 Quarters

High

$

24.22

$

23.46

$

25.49

$

26.37

Low

$

14.27

$

16.86

$

21.97

$

21.78

Cash distributions paid

$

0.583

$

0.583

$

0.583

$

0.583

On February 13, 2018, the last reported sales price of our Class A common units on the NYSE was $13.54. As of January 26, 2018, there were approximately 824 registered holders of record of Class A common units. There is no established public trading market for our Class B common units, Class E units or Class F units all of which are held directly or indirectly by our General Partner, or our i-units, all of which are held by Enbridge Management. For further details regarding our distributions refer to Part II. Item 8. Financial Statements and Supplementary Data— Note 16 - Partners' Capital.

39

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth, for the periods and at the dates indicated, the summary historical financial data. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

December 31,

2017 (1)(2)

2016 (1)

2015 (1)

2014 (1)

2013 (1)

(in millions, except per unit amounts)

Statement of Income Data:

Operating revenues(2)

$

2,428

$

2,516

$

2,303

$

2,070

$

1,524

Operating income(3)

1,121

481

964

934

375

Income from continuing operations(3)

708

116

739

596

143

Income (loss) from discontinued operations, net of tax

(57

)

(157

)

(285

)

144

17

Net income (loss)

651

(41

)

454

740

160

Net income (loss) - controlling interests

245

(162

)

132

372

5

Net income (loss) from continuing operations

237

(268

)

119

74

(123

)

Net income (loss) attributable to common units and i-units

200

(377

)

(85

)

218

5

Net income (loss) per common unit and i-unit (basic and diluted) from continuing operations

0.60

(0.77

)

0.35

0.23

(0.39

)

Net income (loss) per common unit and i-unit (basic and diluted)

0.50

(1.08

)

(0.25

)

0.67

(0.33

)

Cash distributions paid per limited partner unit(4)

1.633

2.332

2.306

2.197

2.174

Statement of Financial Position Data:

Total assets(5)

$

14,828

$

18,110

$

18,774

$

17,727

$

14,881

Long-term debt, excluding current maturities

6,366

7,066

6,838

5,895

4,421

Loans from General Partner and affiliate

610

750

—

—

306

Due to General Partner and affiliates

—

328

238

148

47

Other long-term liabilities

178

197

189

169

20

____________

(1)

On June 28, 2017, we completed the sale of all our interest in our Midcoast gas gathering and processing business to our General Partner. This sale represents a strategic shift in our business and as a result, the results of operations and financial position of our natural gas business from the periods presented are reflected as discontinued operations.

(2)

Our statements of income and financial position reflect the following dispositions:

Date of Disposition

Description of Disposition

December 2017

The disposition of unnecessary pipe related to the Sandpiper Project

March 2017

The disposition of the Ozark Pipeline system

(3)

Operating income for the year ended December 31, 2016, were impacted by a $757 million asset impairment charge in relation to the Sandpiper project as discussed in Item 8. Financial Statements and Supplementary Data— Note 9 - Property, Plant and Equipment.

(4)

On April 28, 2017, we announced the conclusion of our strategic review. As a result, of the strategic review we reduced our quarterly distributions from $0.583 per unit to $0.35 per unit, as discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

(5)

Total assets for the years ended December 31, 2016, 2015, 2014, and 2013 are inclusive of amounts attributable to our interest in our Midcoast gas gathering and processing business which was sold to our General Partner on June 28, 2017.

40

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

RECENT DEVELOPMENTS

US TAX REFORM

On December 22, 2017, United States legislation referred to as the "Tax Cuts and Jobs Act" (the TCJA) was signed into law. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of individual and business entities. The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%.

This tax rate change is expected to cause us to reduce the income tax allowance component of the tolls in our FERC regulated cost-of-service based Facility Surcharge Mechanism (FSM) projects. Impacts of tax reform will be realized in the first quarter of 2018 and will be reflected in Lakehead’s FSM toll filing for rates effective April 1, 2018. The total annual impact to us is expected to be approximately $55 million per year, net of noncontrolling interests (NCI).

ALBERTA CLIPPER (LINE 67) PRESIDENTIAL PERMIT

On October 16, 2017, we received a Presidential Permit for Line 67, following a nearly five-year process of review. Line 67 currently operates under an existing Presidential Permit that was issued by the United States Department of State in 2009 and the 2017 Presidential Permit authorizes us to fully utilize its capacity across the border.

Line 67 is a key component of the Lakehead System, which United States refineries rely on to provide vital products to consumers across the Midwest United States. Refer to Growth Projects — Regulatory Matters — Lakehead System Mainline Expansion for further information.

BAKKEN PIPELINE SYSTEM

On February 15, 2017, through our joint venture with MPC, we completed the acquisition of an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $1.5 billion, initially funded through the Enbridge (U.S.) Inc. (EUS) Credit Agreement. On April 27, 2017, we finalized the joint funding arrangement with our General Partner for our effective interest in the Bakken Pipeline System. Under the terms of the arrangement, our General Partner owns 75% and we own 25% of Enbridge Holdings (DakTex) L.L.C. (DakTex) our investment subsidiary, which in turn owns the joint venture with MPC. We also have a five-year option to acquire an additional 20% interest in DakTex at net book value. With the finalization of the joint funding arrangement, we repaid the $1.5 billion outstanding under the EUS Credit Agreement and terminated the credit agreement. For further information on the EUS Credit Agreement refer to Item 8. Financial Statements and Supplementary Data — Note 20 - Related Party Transactions .

The Bakken Pipeline System, which consists of DAPL and ETCOP, was placed into service June 1, 2017. It transports crude oil from the Bakken formation in North Dakota to markets in eastern PADD II, and the United States Gulf Coast. DAPL consists of 1,172 miles of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to deliver in excess of 470,000 Bpd of crude oil and has the potential to be expanded to 570,000 Bpd. ETCOP consists of 62 miles of new 30-inch diameter pipe, 686 miles of converted 30-inch diameter pipe, and 40 miles of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.

STRATEGIC REVIEW

On April 28, 2017, we announced the conclusion of our strategic review and undertook steps to position us as a pure-play liquids pipeline MLP with a low-risk commercial profile, stable cash flows, a strong balance sheet, healthy distribution coverage, visible growth and limited external capital needs. We implemented the following actions to strengthen our financial position and outlook:

41

•

The reduction of our quarterly distribution from $0.583 per unit to $0.35 per unit or from $2.33 per unit to $1.40 per unit on an annualized basis;

•

Issuance of approximately 64 million Class A common units to our General Partner at a price of $18.66 per Class A common unit;

•

The redemption of our outstanding Series 1 Preferred Units held by the General Partner at face value of $1.2 billion which was funded with the proceeds from the issuance of Class A common units to our General Partner;

•

The sale of all of our interests in our Midcoast gas gathering and processing business which closed on June 28, 2017, to our General Partner for $2.3 billion, including cash consideration of $1.3 billion and $953 million of existing outstanding indebtedness at MEP. A portion of these proceeds were used for other restructuring actions including the repayment of deferred distributions on our Series 1 Preferred Units;

•

Subsequent to the Midcoast sale on June 28, 2017, we repaid $357 million in deferred distribution balance on our Series 1 Preferred Units owed to our General Partner;

•

The restructuring of our capital structure and modification of our incentive distribution rights through the irrevocable waiver by a wholly-owned subsidiary of our General Partner of all of that subsidiary’s 66 million Class D units and 1,000 IDUs in consideration for issuance of a new class of units, Class F units. These units are entitled to (i) 13% of all distributions of available cash in excess of $0.295 per unit, but less than or equal to $0.35 per unit, and (ii) 23% of all distributions of available cash in excess of $0.35 per unit; and

•

The finalization of the joint funding arrangement for our investment in the Bakken Pipeline System in which our General Partner owns 75% interest and we own 25% interest with an option to acquire an additional 20% interest from our General Partner at net book value.

Also, on January 26, 2017, we announced three strengthening actions to alleviate short-term capital expenditure requirements and enhanced our cash flows as follows:

•

We entered into a joint funding arrangement with our General Partner for the U.S. L3R Program whereby our General Partner paid approximately $450 million for a 99% interest in the project, including our share of the construction costs to date and other incremental amounts;

•

We acquired an additional 15% interest in the Eastern Access Projects, at its book value of approximately $360 million, which is now in service. We utilized the funds received from the joint funding arrangement for the U.S. L3R Program to exercise our option under the Eastern Access joint funding arrangement; and

•

MEP entered into the merger agreement with our General Partner, whereby, on April 27, 2017, our General Partner acquired, for cash, all the outstanding publicly held Class A common units of MEP.

Our business outlook as a pure-play liquids pipeline MLP remains strong. The Lakehead System is expected to continue to deliver stable, low-risk regulated cash flow and the volume outlook on the North Dakota assets is expected to remain strong. Our cash flow growth is expected to be underpinned by various sources, including higher contracted volumes on the Bakken Pipeline System and higher toll surcharges on our existing 25% interest in the Mainline Expansion Project when it fully enters service. In addition, we hold purchase options under existing joint funding arrangements to acquire additional interests in the Bakken Pipeline System, the Mainline Expansion Project and the Line 3 Replacement Project. For further details regarding our joint funding arrangement, refer to Item 8. Financial Statements and Supplementary Data — Note 20 - Related Party Transactions.

42

RESULTS OF OPERATIONS — OVERVIEW

We provide services to our customers and returns for our unitholders through our liquids business, which consists of interstate pipeline transportation and storage of crude oil and liquid petroleum. Our liquids business is conducted through three systems: Lakehead System, Mid-Continent System and Bakken Assets. These systems largely consist of FERC regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead System, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.

On June 28, 2017 our General Partner acquired all of our ownership interests in our Midcoast gas gathering and processing business through the acquisition of all of our 48.4% interest in Midcoast Operating, all of our ownership interests in Midcoast Holdings, L.L.C., and all of our limited partnership interests in MEP. For further details regarding the Midcoast sale, refer to Item 8. Financial Statements and Supplementary Data— Note 7 - Dispositions and Discontinued Operations.

The results of our Midcoast gas gathering and processing business are included in “Loss from discontinued operations” in our consolidated statements of income.

The following table reflects our results of operations:

December 31,

2017

2016

2015

(in millions)

Operating revenues

$

2,428

$

2,516

$

2,303

Operating expenses

Operating and administrative

355

283

344

Operating and administrative – affiliate

294

291

294

Power

290

277

260

Depreciation and amortization

442

427

378

Gain on sale of assets

(74

)

—

—

Asset impairment

—

757

63

1,307

2,035

1,339

Operating income

1,121

481

964

Interest expense

(525

)

(413

)

(292

)

Allowance for equity used during construction

47

46

70

Other income

57

1

—

Income from continuing operations before income tax

700

115

742

Income tax benefit (expense)

8

1

(3

)

Income from continuing operations

708

116

739

Loss from discontinued operations, net of tax

(57

)

(157

)

(285

)

Net income (loss)

651

(41

)

454

Net income attributable to noncontrolling interest

(369

)

(26

)

(221

)

Series 1 preferred unit distributions

(29

)

(90

)

(90

)

Accretion of discount on Series 1 preferred units

(8

)

(5

)

(11

)

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.

$

245

$

(162

)

$

132

YEAR ENDED DECEMBER 31, 2017 COMPARED TO YEAR ENDED DECEMBER 31, 2016

Operating Revenue

Operating revenues decreased$88 million for the year ended December 31, 2017 when compared to the corresponding 2016 period. The decrease was mainly driven by:

43

•

Lower operating revenue from our North Dakota System resulting from lower volumes and tolls on our Bakken System due to the expiration of the Phase 5 Looping and Phase 6 Mainline surcharges at the end of 2016 and lower operating revenue from our Berthold rail facility;

•

Lower operating revenue from our Mid-Continent System as a result of the sale of the Ozark Pipeline on March 1, 2017, lower Cushing Terminal activity and fixed storage contracts; partially offset by

•

Higher operating revenue from the Lakehead System due to increased flow-through of recoverable operating costs attributable to higher throughput on the Lakehead System.

Operating Expenses

Operating expenses decreased$728 million for the year ended December 31, 2017 when compared to the corresponding 2016 period. The decrease was mainly driven by:

•

The absence in 2017 of a one-time impairment loss of $757 million that occurred in 2016 related to the withdrawal of our regulatory application on the Sandpiper Project;

•

Gain on the sale of unnecessary pipe related to the Sandpiper Project;

•

Lower Mid-Continent operating expenses resulting from the sale of Ozark Pipeline on March 1, 2017; partially offset by

•

Higher Lakehead System pass-through power costs driven by higher throughput and other operating expenses which will be partially recoverable in 2018.

Interest Expense

Interest expense increased$112 million for the year ended December 31, 2017 when compared to the corresponding 2016 period. The increase was mainly driven by:

•

The termination of interest rate swaps due to a high probability that the long-term debt associated with the interest rate swaps would not be raised, resulting in the reclassification of realized losses to interest expense from accumulated other comprehensive income (AOCI).

Other Income

Other income increased$56 million for the year ended December 31, 2017 when compared to the corresponding 2016 period. The increase was mainly driven by:

•

Equity earnings from our interest in the Bakken Pipeline System, which was placed into service on June 1, 2017

Loss from discontinued operations, net of tax

Our loss from discontinued operations decreased$100 million when compared to the corresponding 2016 period. The decrease was mainly driven by:

•

The sale of our Midcoast gas gathering and processing business during the second half of 2017 to our General Partner resulting in the absence of full year of losses from our Midcoast gas gathering and processing business.

Income attributable to noncontrolling interests (NCI)

Income attributable to NCI increased$343 million when compared to the corresponding 2016 period. The increase was mainly driven by:

•

The absence in 2017 of a one-time impairment loss of $757 million that occurred in 2016 related to the withdrawal of our regulatory application on the Sandpiper Project of which $267 million was attributable to NCI;

•

The sale of all our interest in our Midcoast gas gathering and processing business resulting in the absence of losses attributable to NCI; and

•

The finalization of a joint funding arrangement with our General Partner whereby our General Partner owns 75% of DakTex, our consolidated subsidiary, which holds our equity investment in MarEn Bakken Company LLC(MarEn) resulting in an increase to NCI.

Series 1 Preferred Units Distribution

Distribution to Series 1 Preferred Units decreased$61 million when compared to the corresponding 2016 period. The decrease was mainly driven by:

44

•

The April 27, 2017, redemption of our outstanding Series 1 Preferred Units resulting in the absence of a full year of distribution. The Series 1 Preferred Units received a full year of distribution in 2016.

YEAR ENDED DECEMBER 31, 2016 COMPARED TO YEAR ENDED DECEMBER 31, 2015

Operating Revenue

Operating revenues increased$213 million for the year ended December 31, 2016 when compared to the corresponding 2015 period. The increase was mainly driven by:

•

Increased surcharge revenue from projects subject to regulatory accounting. This increase is a result of placing $1.6 billion of additional assets into service on the Lakehead System in 2015.

•

Partially offset by a decrease on the North Dakota System due to lower average rates and lower rail revenues. The lower rail revenues were attributable to expired contracts on the Berthold rail facility.

Operating Expenses

Operating expenses increased$696 million for the year ended December 31, 2016 when compared to the corresponding 2015 period. The increase was mainly driven by:

•

An asset impairment of $757 million in relation to the withdrawal of our regulatory application on the Sandpiper Project in 2016; partially offset by

•

The absence in 2016 of an asset impairment of $63 million to write-off the remaining carrying value of our Berthold rail facility due to contracts that were not renewed.

Interest Expense

Interest expense increased$121 million for the year ended December 31, 2016 when compared to the corresponding 2015 period. The increase was mainly driven by:

•

An increase in our average outstanding debt balance during the year ended December 31, 2016, which includes $1.6 billion of senior unsecured notes that were issued in October 2015.

Allowance for equity used during construction

Allowance for equity used during construction (AEDC) decreased$24 million for the year ended December 31, 2016 when compared to the corresponding 2015 period. The decrease was mainly driven by:

•

A reduction in outstanding capital projects as the Eastern Access project was completed and placed into service in June 2016.

Loss from discontinued operations, net of tax

Our loss from discontinued operations decreased$128 million when compared to the corresponding 2015 period. The decrease was mainly driven by:

•

The absence in 2016 of a goodwill impairment charge recorded in 2015 of $247 million due to sustained and prolonged reductions in drilling activities due to low prices for natural gas and NGLs; partially offset by;

•

Lower margins primarily due to decreases in commodity prices and the resulting decrease in volumes from reduced drilling activities.

Income attributable to NCI

Income attributable to NCI decreased$195 million when compared to the corresponding 2015 period. The decrease was mainly driven by:

•

A one-time asset impairment in 2016 of $757 million in relation to the withdrawal of our regulatory application on the Sandpiper Project of which $267 million was attributable to NCI; partially offset by;

•

Higher earnings attributable to both the Eastern Access and United States Mainline Expansion projects.

DERIVATIVE TRANSACTIONS AND HEDGING ACTIVITIES

Contractual arrangements expose us to market risks associated with changes in (i) commodity prices where we receive crude oil in return for the services we provide or (ii) interest rates on our variable rate debt. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. We use derivative financial instruments such as futures, forwards, swaps, options and other financial

45

instruments with similar characteristics, to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. Derivative financial instruments that do not receive hedge accounting under the provisions of authoritative accounting guidance create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as follows:

•

Commodity-based derivatives — “Transportation and other services”

•

Interest rate derivatives — “Interest expense, net”

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:

December 31,

2017

2016

2015

(in millions)

Liquids segment:

Non-qualified hedges

$

(3

)

$

(9

)

$

(16

)

Other:

Interest rate hedge ineffectiveness

50

(7

)

99

Derivative fair value net gains (losses)

$

47

$

(16

)

$

83

RESULTS OF OPERATIONS — BY SEGMENT

SEGMENT RESULTS

Management evaluates segment performance based on earnings before interest, taxes and depreciation and amortization (EBITDA). We consider segment EBITDA the indicator of our segment's operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.

LIQUIDS

Our Liquids segment includes the operations of our Lakehead System, Mid-Continent System and Bakken Assets. We provide a detailed description of each of these systems in Part I.Item 1. Business. The following table sets forth the operating results and statistics of our Liquids segment assets for the periods presented:

46

December 31,

2017

2016

2015

(in millions)

Operating Results:

Operating revenues

$

2,428

$

2,516

$

2,303

Operating expenses:

Operating and administrative

(637

)

(564

)

(609

)

Power

(290

)

(277

)

(260

)

Gain on sale of assets

74

—

—

Asset impairment

—

(757

)

(63

)

Allowance for equity used during construction

47

46

70

Other income

52

—

—

EBITDA

$

1,674

$

964

$

1,441

Operating Statistics:

Lakehead System:

United States(1)

2,027

1,968

1,869

Canada(1)

646

606

446

Total Lakehead System delivery volumes(1)

2,673

2,574

2,315

Barrel miles (billions)

756

724

640

Average haul (miles)

775

768

757

Mid-Continent System delivery volumes(1)

24

188

212

Bakken Assets:

North Dakota System to Clearbrook(1)

214

216

208

Bakken System to Cromer(1)

115

136

88

Total Bakken Assets delivery volumes(1)

329

352

296

Total Liquids segment delivery volumes(1)

3,026

3,114

2,823

____________

(1)

Average barrels per day in thousands.

Year ended December 31, 2017 compared to year ended December 31, 2016

EBITDA increased $710 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016. The increase in EBITDA was primarily due to the following items:

•

The absence in 2017 of an asset impairment loss of $757 million in 2016 on our Sandpiper Project as noted below.

•

A decrease in Lakehead System EBITDA as a result of a lower Lakehead System Local Toll, the expiry of the Line 2B hydrotest surcharge at the end of 2016 and higher operating costs which will be partially recoverable in 2018.

•

EBITDA from our North Dakota System was consistent year over year with EBITDA from our interest in the Bakken Pipeline System, which was placed into service in June 2017, offsetting lower EBITDA resulting from lower volumes and tolls on our Bakken System due to the expiration of the Phase 5 Looping and Phase 6 Mainline surcharges at the end of 2016 and lower EBITDA from our Berthold rail facility due to expiration of customer contracts.

•

Lower EBITDA from our Mid-Continent System as a result of the sale of the Ozark Pipeline on March 1, 2017 and to lower Cushing Terminal activity and fixed storage contracts.

Year ended December 31, 2016 compared to year ended December 31, 2015

EBITDA decreased$477 million for the year ended December 31, 2016 when compared to the corresponding 2015 period. The decrease in EBITDA was primarily due to the following items:

47

•

We recognized an asset impairment loss of $757 million in 2016 due to the withdrawal of our regulatory application on the Sandpiper Project. In 2015, we recognized an asset impairment loss of $63 million to write-off the remaining carrying value of our Berthold rail facility due to contracts that were not renewed in 2015.

•

Further contributing to the decrease was lower rail revenues primarily attributable expired contracts on the Berthold rail facility and greater qualifying volumes credits related to the Lakehead toll revenues.

•

Partially offsetting the decrease in EBITDA was increased surcharge revenue for projects subject to regulatory accounting. The increase is attributable to placing $1.6 billion of additional assets into service on the Lakehead System in 2015 and lower operating and administrative expenses due to lower pipeline integrity costs related to hydrostatic test on Line 2B in 2015. There were no such costs incurred for the year ended December 31, 2016.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

We currently have a multi-billion dollar growth program underway, with projects expected to come into service in 2019, in addition to options to increase our economic interest in projects that are jointly funded by Enbridge and us.

The table and discussion below summarizes our commercially secured projects for the Liquids segment. Expenditures to date reflect total cumulative expenditures incurred from the inception of the projects to December 31, 2017.

Projects

Ownership Interest

Total Estimated Capital Costs(1)

Expenditures to Date(2)

Status

Expected In-Service Date

Lakehead System Mainline Expansion - Line 61(3)(4)

25

%

0.4 billion

0.4 billion

Substantially Complete

2H -2019

U.S. Line 3 Replacement Program(5)

1%

2.9 billion

0.7 billion

Under construction

2H -2019

____________

(1)

These amounts are estimates and are subject to upward or downward adjustment based on various factors.

(2)

Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2017.

(3)

Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion Joint Funding Arrangement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

(4)

Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

(5)

The Conflicts Committee and Board of Directors approved a joint funding arrangement with our General Partner for the U.S. L3R Program. The General Partner will fund 99% and we will fund 1% of the capital cost of the U.S. L3R Program.

The following commercially secured growth projects are expected to be placed in 2019:

•

Lakehead System Mainline Expansion - The remaining scope of the project includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois that will increase capacity from 950,000 Bpd to 1,200,000 Bpd, which was substantially completed in June of 2017. We currently anticipate an in-service date in second half of 2019 for this phase to more closely align with the anticipated in-service date for the U.S. L3R Program. For additional updates on the project, refer to Growth Projects - Regulatory Matters.

•

U.S. Line 3 Replacement Program - replacement of the existing Line 3 crude oil pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S. L3R Program, along with the Canadian L3R Program, will support the safety and operational reliability of the mainline system, enhance system flexibility, and allow us to optimize throughput on the mainline. The L3R Program is expected to achieve the original capacity of approximately 760,000 Bpd. Construction commenced on the Wisconsin portion of the U.S. L3R Program in late June 2017 and will be substantially complete in February 2018. For additional updates on the project, refer to Growth Projects - Regulatory Matters.

48

GROWTH PROJECTS - REGULATORY MATTERS

LAKEHEAD SYSTEM MAINLINE EXPANSION

On October 16, 2017, the United States Department of State issued a Presidential Permit to us to operate Line 67 at its design capacity of 888,889 Bpd at the international border of the United States and Canada near Neche, North Dakota.

U.S. LINE 3 REPLACEMENT PROGRAM

We are in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need (Certificate) and an approval of the pipeline’s route (Route Permit) from the MNPUC. The MNPUC found both the Certificate and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the Minnesota Public Utilities Commission (MNPUC) issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final EIS to be inadequate in four specific areas on December 7, 2017. The DOC provided a supplemental EIS on February 12, 2018 and the MNPUC will determine its adequacy in the second quarter of 2018. Progress continues with the parallel Certificate and Route Permit dockets, with public and evidentiary hearings now complete. The MNPUC is expected to issue a ruling in the second quarter of 2018. Construction of the Wisconsin portion of the U.S. Line 3 Replacement program began in late June 2017 and will be mechanically complete by February 2018.

REGULATORY PERMITTING

Our multi-billion dollar growth program includes investments in joint ventures as described above and organic growth projects. In recent years, proposed projects in our industry have faced unexpected extensions in the regulatory permitting process, which has created delays in and uncertainty related to timing of certain projects. Delays in the in service dates of our projects may have a significant impact on our forecasts and our financial results.

In addition environmental and indigenous opposition to the construction and operation of pipelines has impacted the industry, including us. We undertake extensive engagements with all stakeholders that are impacted by our projects in order to meet the needs of the public and ensure that issues are identified and managed. This effort includes land owners, communities, all levels of government and Tribal leadership, regulators and permitting agencies.

We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities although there can be no assurance that such financings will be available on favorable terms, if at all.

In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, our General Partner provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from our General Partner, but there can be no assurance that this funding can be obtained.

expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities. At December 31, 2017, we had approximately $1.2 billion in available credit under the terms of our Credit Facilities.

We are also party to certain financing arrangement with affiliates under an unsecured revolving 364-day credit agreement with EUS. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750 million. Additionally, we entered into the EUS Credit Agreement, for the sole purpose of providing interim financing for our investment in the Bakken Pipeline System. On April 27, 2017, we finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System. As a result of the joint funding arrangement, we repaid the outstanding balance of $1.5 billion under the EUS Credit Agreement and terminated the agreement. For further details on our financing arrangements with affiliates refer to Item 8. Financial Statements and Supplementary Data— Note 20 - Related Party Transactions

At December 31, 2017, we had a working capital deficit of approximately $0.6 billion. We had approximately $1.3 billion of consolidated liquidity, which we expect to be sufficient, to meet our ongoing operational, investing and financing needs as described above, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil release on Line 6B.

The following table sets forth the consolidated liquidity available to us at December 31, 2017.

December 31,

(in millions)

Cash and cash equivalents

$

35

Total capacity under the Credit Facilities

2,625

Total capacity under the EUS 364-day Credit Facility

750

Less: Amounts outstanding under the Credit Facilities

150

Amounts outstanding under the EUS 364-day Credit Facility

610

Principal amount of commercial paper outstanding

1,303

Letters of credit outstanding

1

Total

$

1,346

CAPITAL RESOURCES

Debt and Equity Securities

Execution of our growth strategy and completion of our planned construction projects contemplate accessing the capital markets to obtain the necessary funding for these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our organic growth projects and targeted acquisitions will require additional permanent capital and may require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. From time to time, if the capital markets are constrained, our ability and willingness to complete future debt and equity offerings may be limited, which in turn, could affect our ability to execute our growth strategy or complete our planned construction projects. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit ratings at the time.

Our current shelf registration statement on Form S-3, which would allow us to issue an unlimited amount of equity and debt securities in underwritten public offerings expires in February of 2018. Unless we seek, and receive a waiver from the SEC, no further issuances will be made under this shelf registration statement and a new shelf registration statement would not be expected to be filed until August of 2018, at the earliest. The delay in filing a new shelf registration statement is due to the late filing of pro forma financial information after the sale of our Midcoast gas gathering and processing business to our General Partner. Until a new shelf registration statement on Form S-3 is filed with the SEC, any issuances of debt or equity securities in underwritten public offerings would utilize a different form of registration statement or we could seek to issue debt securities in a private placement.

50

Commercial Paper

Our commercial paper program provides for the issuance of up to an aggregate principal amount $1.5 billion of commercial paper and is supported by our Credit Facilities.

Credit Facilities

Our primary Credit Facility permits aggregate borrowings of up to, at any one time outstanding, $2.0 billion with a letter of credit subfacility and a swing line subfacility. On October 2, 2017, we extended the maturity date attributable to the Credit Facility to September 26, 2022; however, $185 million of the commitments will expire on September 26, 2020 and $175 million will expire on September 26, 2018. In 2016, we amended the Credit Facility to increase the lending commitments by $25 million from $1,975 million. Loans under the Credit Facility accrue interest either at a eurocurrency rate or at a base rate, in each case, plus an applicable margin.

The 364-day Credit Facility, permits aggregate borrowings of up to $625 million: (i) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion, and (ii) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. On June 30, 2017, the termination date was extended to June 29, 2018, which has a term out option that could extend maturity of outstanding borrowings to June 28, 2019.

At December 31, 2017, our Credit Facilities provided an aggregate amount of approximately $2.6 billion of bank credit, which we use to fund our general activities and working capital needs.

In addition, the EUS 364-day Credit Facility permits aggregate borrowing of up to, at any one time outstanding, $750 million. We entered into an agreement with EUS on July 25, 2017, whereby the termination date was extended to July 24, 2018. The EUS 364-day Credit Facility is discussed in Item 8. Financial Statements and Supplementary Data— Note 20 - Related Party Transactions.

As of December 31, 2017, we were in compliance with the terms of all of our financial covenants under the Credit Facilities.

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2017 and 2015. There were no issuances of Class A common units for the years ended December 31, 2016.

Issuance Date

Number of

Class A

common unit

Issued

Price

per Class A

common units

Net Proceeds

to the

Partnership(1)

General

Partner

Contribution(2)

Net Proceeds Including General Partner Contribution

(in millions, except units and per unit amounts)

April, 2017

64,308,682

$

18.66

$

1,200

$

24

$

1,224

March, 2015

8,000,000

$

36.70

$

289

$

6

$

295

____________

(1)

Net of underwriters’ fees and discounts, commissions and issuance expenses.

(2)

Contributions made by the General Partner to maintain its 2% general partner interest.

The proceeds from the April 2017 issuance were used to redeem in full our $1.2 billion of outstanding Series 1 Preferred Units held by our General Partner.

The proceeds from the March 2015 offering were used to fund a portion of our capital expansion projects and for general partnership purposes.

Senior Notes

Our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200 million of senior notes issued by the OLP (the OLP Notes). The OLP Notes represent unsecured obligations that are structurally senior to our senior notes. All of the OLP Notes pay interest semi-annually. For further details regarding the OLP Notes, refer to Item 8. Financial Statements and Supplementary Data— Note 13 - Debt.

51

Junior Subordinated Notes

The $400 million in principal amount of our fixed to floating rate, junior subordinated notes due 2067 (the Junior Notes) represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. Prior to October 1, 2017, the Junior Notes bore interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year. Effective October 1, 2017, the Junior Notes bear interest at a variable rate equal to the three month LIBOR for the related interest period increased by 3.798%, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. We may elect to defer interest payments on the Junior Notes for up to ten consecutive years on one or more occasions, but not beyond the final repayment date. Until paid, any interest we elect to defer will bear interest at the prevailing interest rate, compounded quarterly. For further details regarding the junior subordinated notes, refer to Item 8. Financial Statements and Supplementary Data— Note 13 - Debt.

Joint Funding Arrangements

In order to obtain capital, we have explored, and may continue to explore, numerous options, including joint funding arrangements. For certain of our joint funding arrangements currently in place, we have an option to increase our ownership of certain assets. For further details regarding our existing joint funding arrangements, including the option periods and exercise price of certain options held by us, refer to Item 8. Financial Statements and Supplementary Data— Note 20 - Related Party Transactions.

Sale of Accounts Receivable

We and certain of our subsidiaries were parties to a receivable purchase agreement (Receivables Agreement), with an indirect, wholly-owned subsidiary of Enbridge.On April 27, 2017, we terminated our Receivables Agreement with the indirect, wholly-owned subsidiary of Enbridge in exchange for a one-time $5 million payment to us. As a result, of this termination we discontinued the sale of our receivables balance. Prior to termination of the Receivables Agreement, the Enbridge subsidiary would purchase on a monthly basis, for cash, current accounts receivable and accrued receivables (the receivables) of the respective subsidiaries initially up to a monthly maximum of $450 million. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables were deposited in an account of that subsidiary, and ownership and control were vested in that subsidiary. The Enbridge subsidiary had no recourse against us with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement.

We incurred capital expenditures of $586 million for the year ended December 31, 2017, including $40 million of maintenance capital expenditures. Of those capital expenditures, $300 million was financed by contributions from our General Partner via joint funding arrangements. At December 31, 2017, we had approximately $252 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.

Acquisitions

On February 15, 2017, through our joint venture with MPC we acquired an effective 27.6% interest in the Bakken Pipeline System. We funded the $1.5 billion acquisition through a bridge loan provided by an affiliate of our General Partner. On April 27, 2017, our Board of Directors finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System. We used the amounts received from the finalization of the joint funding arrangement plus additional borrowing from our existing facility to repay the $1.5 billion outstanding and subsequently terminated the bridge loan provided by an affiliate of our General Partner. For further details regarding our funding arrangements refer to Item 8. Financial Statements and Supplementary Data— Note 20 - Related Party Transactions

Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. For the year ended December 31, 2018. we forecast total expenditures of approximately $780 million, inclusive of $40 million related to maintenance capital. We expect to fund $362 million and the remaining $418 million will be funded

52

by our General Partner based on our joint funding arrangements for the U.S. L3R Program, Eastern Access Projects, and Mainline Expansion Projects. Although we anticipate making these expenditures in 2018, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, regulatory permitting, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

Distributions

We make quarterly distributions to our General Partner and the holders of our limited partner interests in an amount equal to our “available cash.” As defined in our partnership agreement, “available cash” represents for any calendar quarter, the sum of all of our cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. We establish reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and the General Partner and, as necessary, to comply with the terms of any of our agreements or obligations. Enbridge Management, as the delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.”

Enbridge Management, as the owner of our i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to our limited partners and General Partner, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management’s listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management’s listed shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for Enbridge Management’s shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to our General Partner.

For purposes of calculating the sum of all distributions of available cash, the cash equivalent amount of the additional i-units that are issued when a distribution of cash is made to our General Partner and limited partner interests is treated as a distribution of available cash. As set forth in our partnership agreement, we will not make cash distributions on our i-units, but instead will distribute additional i-units such that cash is retained and used in our operations and to finance a portion of our capital expansion projects. During 2017, we distributed a total of 7,941,650 i-units through quarterly distributions to Enbridge Management, compared with 8,571,429 and 4,980,552 in 2016 and 2015, respectively.

The following table represents cash we have retained in our business since January 2015 from the in-kind distribution of additional i-units:

53

Distribution Payment Date

Amount

Retained for

Distribution

to i-units

Holders(1)

Retained

from General

Partner(2)

Total Cash

Retained

(in millions)

2017

November 14

$

30

$

1

$

31

August 14

29

1

30

May 15

30

1

31

February 14

48

1

49

$

137

$

4

$

141

2016

November 14

$

47

$

1

$

48

August 12

45

1

46

May 13

44

1

45

February 12

43

1

44

$

179

$

4

$

183

2015

November 13

$

41

$

1

$

42

August 14

41

1

42

May 15

40

1

41

February 13

39

1

40

$

161

$

4

$

165

____________

(1)

We issued 1,000 i-units to Enbridge Management, the sole owner of our i-units, during 2017 in lieu of cash distributions.

(2)

We retained an amount equity to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

On April 28, 2017, we announced the reduction of our quarterly distribution from $0.583 per unit to $0.35 per unit or from $2.33 per unit to $1.40 on an annualized basis. Our annual cash distribution rate was $1.63 per unit, as the distribution declared for the three months ended December 31, 2016, was distributed as cash in the first quarter of 2017 at $0.583 per unit. Subsequent distributions were distributed at $0.35 per unit.

We expect that all cash distributions will be paid out of operating cash flows over the long term. However, from time to time, we may temporarily borrow under our Credit Facilities or use cash retained by issuance of payment in-kind distributions for the purpose of paying cash distributions. We may do this until we realize the full impact of assets being developed on operations or to respond to short-term aberrations in our performance caused by market disruption events or depressed commodity prices. As various projects are under construction, we expect our coverage ratio to weaken as assets under construction do not generate cash flow until they enter service and we are bearing the related financial costs. We expect that our major capital expansion projects will be accretive to distributable cash flow when they are operational and the coverage ratio to then improve.

Amendment of OLP Limited Partnership Agreement

On July 30,2015, the partners amended and restated the limited partnership agreement of the OLP pursuant to which our General Partner temporarily did not receive Series EA and ME (the Series) distributions from the quarter ended June 30, 2015, through the quarter ended March 31, 2016. The General Partner's capital funding contribution requirements for each of those two Series, commencing in August 2015, were reduced by the amount of its foregone cash distributions from the respective Series, until the earlier of December 31, 2016 and the date aggregate reductions in capital contributions for such Series are equal to the foregone cash distributions from such Series. As of December 31, 2016, capital contributions offsets foregone cash distributions.

Distribution to Series EA Interests

54

The following table presents distributions paid by the OLP for the years ended December 31, 2017, 2016, and 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests.

Distribution

Declaration Date

Distribution

Payment Date

Amount Paid

to EEP

Amount Paid to the

noncontrolling interest

Total Series EA

Distribution

(in millions of dollars)

2017

October 25

November 14

$

35

$

51

$

86

July 28

August 14

33

50

83

April 27

May 15

29

62

91

January 26

February 14

23

69

92

$

120

$

232

$

352

2016

October 28

November 14

$

22

$

65

$

87

July 28

August 12

21

63

84

April 29

May 13

79

—

79

January 29

February 12

79

—

79

$

201

$

128

$

329

2015

October 30

November 13

$

76

$

—

$

76

July 30

August 14

76

—

76

April 30

May 15

18

52

70

January 29

February 13

22

67

89

$

192

$

119

$

311

Distribution to Series ME Interests

The following table presents distributions paid by the OLP for the years ended December 31, 2017, 2016, and 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series ME interests.

55

Distribution

Declaration Date

Distribution

Payment Date

Amount Paid

to EEP

Amount Paid to the

noncontrolling interest

Total Series ME

Distribution

(in millions of dollars)

2017

October 25

November 14

$

15

$

44

$

59

July 28

August 14

14

41

55

April 27

May 15

13

38

51

January 26

February 14

14

43

57

$

56

$

166

$

222

2016

October 28

November 14

$

15

$

44

$

59

July 28

August 12

13

40

$

53

April 29

May 13

43

—

$

43

January 29

February 12

41

—

$

41

$

112

$

84

$

196

2015

October 30

November 13

$

32

$

—

$

32

July 30

August 14

20

—

$

20

April 30

May 15

1

5

$

6

January 29

February 13

2

5

$

7

$

55

$

10

$

65

Distribution from Enbridge Holdings (DakTex) L.L.C.

The following table presents distributions paid by Enbridge Holdings (DakTex) L.L.C. (DakTex) during the years ended December 31, 2017, to our General Partner and its affiliates, representing noncontrolling interest in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.

Distribution

Declaration Date

Distribution

Payment Date

Amount Paid

to EEP

Amount Paid to the

noncontrolling interest

Total DakTex

Distribution

(in millions of dollars)

2017

December 19

December 28

$

11

$

32

$

43

September 25

September 29

10

31

41

$

21

$

63

$

84

Distribution from MEP

The following table presents distributions paid by MEP during the years ended December 31, 2017, 2016, 2015, and prior to its sale to our General Partner on June 28, 2017, representing the noncontrolling interest in MEP and to us for our ownership of Class A common units. No distributions were made after the sale.